FERC Form

THIS FILING IS

Item 1:

☑ An Initial (Original) Submission

OR

☐ Resubmission No.




FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

San Diego Gas & Electric Company

Year/Period of Report

End of:

2021

/

Q4

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
1. one million megawatt hours of total annual sales,
2. 100 megawatt hours of annual sales for resale,
3. 500 megawatt hours of annual power exchanges delivered, or
4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).

What and Where to Submit

Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426

For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

The CPA Certification Statement should:

Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

Schedules	Pages
Comparative Balance Sheet	110-113
Statement of Income	114-117
Statement of Retained Earnings	118-119
Statement of Cash Flows	120-121
Notes to Financial Statements	122-123

The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.
“In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.

When to Submit
FERC Forms 1 and 3-Q must be filed by the following schedule:
1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS

Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
'Person' means an individual or a corporation;
'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......

"project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.

Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10

"Sec. 309.

The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM NO.

1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

IDENTIFICATION

01 Exact Legal Name of Respondent

San Diego Gas & Electric Company

02 Year/ Period of Report

End of:

2021

/

Q4

03 Previous Name and Date of Change (If name changed during year)

/

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

8330 Century Park Court, San Diego, CA 92123

05 Name of Contact Person

Eric Dalton

06 Title of Contact Person

Regulatory Reporting Manager

07 Address of Contact Person (Street, City, State, Zip Code)

8330 Century Park Court, San Diego, CA 92123

08 Telephone of Contact Person, Including Area Code

(858) 503-5130

09 This Report is An Original / A Resubmission

(1)

☑ An Original

(2)

☐ A Resubmission

10 Date of Report (Mo, Da, Yr)

04/15/2022

Annual Corporate Officer Certification

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Valerie Bille

02 Title

VP, Controller and CAO

03 Signature

Valerie Bille

04 Date Signed (Mo, Da, Yr)

04/15/2022

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. Valerie Bille VP, Controller and CAO 488 8th Ave. San Diego, CA 92101
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. State of Incorporation: CA Date of Incorporation: 1905-04-06 Incorporated Under Special Law:
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated. Electric and Natural Gas Service - California
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) ☐ Yes (2) ☑ No

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.

The common stock of San Diego Gas & Electric is owned 100% by Enova Corporation, the common stock of which is owned 100% by Sempra Energy.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

CORPORATIONS CONTROLLED BY RESPONDENT
Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	Chief Executive Officer	Winn, Caroline A.	600,000
2	President and Chief Financial Officer	Folkmann, Bruce A.	463,500
3	Vice President, Chief Accounting Officer, Treasurer, Controller	Bille, Valerie A.	242,400
4	Senior Vice President, General Counsel, Chief Risk Officer	Day, Diana L.	366,700
5	Corporate Secretary	Robinson, April R.	259,020

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

DIRECTORS
Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Robert J. Borthwick, Director (1)	San Diego, CA
2	Erbin B. Keith, Director (1)	San Diego, CA
3	Trevor I. Mihalik, Director (1)(2)	San Diego, CA
4	Kevin C. Sagara, Director and Non-executive Chairman(1)	San Diego, CA
5	Caroline A. Winn, Director and Chief Executive Officer	San Diego, CA

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☐ Yes ☐ No
Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	FERC Electric Tariff, Volume No.11	ER21-301-000
2	FERC Electric Tariff, Volume No.11	ER21-526-000
3	FERC Electric Tariff, Volume No.11	ER21-617-000
4	FERC Electric Tariff, Volume No.11	ER21-675-000
5	FERC Electric Tariff, Volume No.11	ER21-320-000
6	FERC Electric Tariff, Volume No.11	ER21-243-000

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☐ Yes ☑ No (Checked by default - Not explicitly defined)
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1	20201102-5091	11/02/2020	ER21-301-000	2021 Transmission Revenue Balancing Account Adjustment ("TRBAA") Filing	FERC Electric Tariff, Volume No.11
2	20201201-5184	12/01/2020	ER21-526-000	TO5 Cycle 3 Formula Rate Tariff Filing	FERC Electric Tariff, Volume No.11
3	20201210-5079	12/10/2020	ER21-617-000	2021 Transmission Access Charge Balancing Account, Adjustment ("TACBAA") Filing	FERC Electric Tariff, Volume No.11
4	20201217-5126	12/17/2020	ER21-675-000	2021 Reliability Service Balancing Account ("RSBA") Filing	FERC Electric Tariff, Volume No.11
5	20201030-5458	10/30/2020	ER21-320-000	Appendix XII Cycle 3 Formula Rate Filing	FERC Electric Tariff, Volume No.11
6	20201029-5104	10/29/2020	ER21-243-000	Appendix X Cycle 9 Formula Rate Filing	FERC Electric Tariff, Volume No.11

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

INFORMATION ON FORMULA RATES - Formula Rate Variances
If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact.
Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission.
Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization.
Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
State the estimated annual effect and nature of any important wage scale changes during the year.
State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
(Reserved.)
If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

On 05/26/2021, the City of San Diego City Council voted to approve new gas and electric franchise agreements with SDG&E. Per the requirements of the City of San Diego City Charter, a second reading and vote was held on 06/08/2021, where a supermajority of the San Diego City Council confirmed their initial vote to approve these new agreements. The agreement is effective as of July 2021. This recent Council action is the subject of ongoing litigation.

None

SDG&E amended its current License for space located on Beech St., extending the term six additional months, expiring 06/30/2022. Written notice was provided to Landlord on 12/30/2021 to vacate hangar 3 located at Joe Crosson Dr. effective 01/31/2022.

In the first quarter of 2021, there were no notable changes to the Transmission System.

In the second quarter of 2021, notable changes to the Transmission System included:

TL654

Conductor changed from 1-750 CU to 1-1033.5 ACSR/AW (MS RACK to Z91103)

Conductor changed from 1-250-CU B.S to 1-750 CU B.S (Z2153273111 to STA F RACK)

TL13816

New substation San Juan Capistrano added

Conductor 1-3000 KCMIL CU is added from SJC 138kv GIS to Z125642 (577 ft; 0.1 mile)

Conductor 1-1033.5 ACSR/AW is added from Z125652 to Z31482 (700 ft; 0.13 miles)

Conductor 1-1033.5 ACSR/AW is removed from CP Rack to Z125642 (around 650 ft; 0.12

mile). Conductor is removed from Z125642 to Z31482 (around 750 ft; .14 mile)

In the third quarter of 2021, notable changes to the Transmission System included:

TL6988 [Valley Center - Terra Gen]

New tie line is energized on 08/03/2021

Conductor added 1-3500 KCMIL AL (.31 miles)

TL6957 [Loveland – Barrett]

Loveland by SWAP project WO 2989040.

LL Rack to Z293865, conductor added 1-636 ACSS/AW (0.06 miles)

From Z293865 to Z293866, conductor added 1-3000 KCMIL CU (0.075 miles)

TL6914 [Los Coches – Loveland]

Loveland by SWAP project WO2989040

From Z293865 -Z293866, conductor added 1-3000 KCMIL CU (0.075 miles)

TL648 [Rancho Carmel – Poway]

Replace cable pole and UG cable at RCL sub.

RCL RACK - Z812075, conductor added 1-3000 KCMIL CU (.12 miles). Old conductor removed 1-1750 KCMIL AL (.10 miles)

TL616 [Rancho Santa Fe – Artesian Ranch – Lake Hodges Metering Sub]

Artesian 230kv expansion project. Re-route from SF -BE - LHP station to SF-ARR-LHM SUB. Substation

name change Artesian Sub -> Artesian Ranch sub; Lake Hodges Pump sta. -> lake Hodges Metering sub.

From Z611159 to Z61119, conductor removed 1-636 ACSR/AW (3 miles).

From Z611199 to Z163663, conductor removed 1-1033.5 ACSR/AW (1.45 miles)

From Z163663 to BE rack, conductor removed 1-1750 KCMIL AL (.05 miles)

From Z611159 to Z254619, conductor added 1-636-ACSR/AW (2 miles);

From Z254619 to ARR rack, conductor added 1-3000 KCMIL CU (.18 miles)

TL6974 [Artesian Ranch – Bernardo Sub]

New tie line is energized 10/13/2021

ARR RACK to Z254404, conductor added 1-3000 KCMIL CU (.15 miles)

Z254404 to Z254617, conductor added 1-636 INVAR (2.15 miles)

Z254617 to BE rack, conductor added 1-3000 KCMIL CU (.13 miles)

In the fourth quarter of 2021, notable changes to the Transmission System included:

TL23069 [DREW SWITCHARD – DW GEN 7]

TL23069 newly energized 11/16/21. 1-1250 KCMIL AL is added from Drew Rack to DW GEN 7 755ft (.14 miles) WO# 5986201

TL692 [LAS PULGAS – JAPANESE MESA]

Wood to steel and reconductor (WO# 2981410) Remove old conductor from LP rack to JA Rack 1-1/0 CU B.S. (6.66 miles) Add new conductor from LP rack to JA rack 1-636 ACSR/AW (6.65 miles)

There were no important changes to the distribution system.

During the first quarter of 2021, SDG&E issued commercial paper with an average daily balance of $25.8 million and a maximum outstanding balance of $156.8 million. The quarter-end balance was $129.9 million.

On 03/12/2021, SDG&E paid off the $200 million 364-day term loan.

During the second quarter of 2021, SDG&E issued commercial paper with an average daily balance of $353.9 million and a maximum outstanding balance of $473 million. The quarter-end balance was $437.5 million.

During the third quarter of 2021, SDG&E issued commercial paper with an average daily balance of $115.9 million and a maximum outstanding balance of $388 million. The quarter-end balance was $0 million. In addition, SDG&E borrowed $375 million under a 364-day term loan, maturing 06/27/2022.

During the third quarter of 2021, on 08/13/2021, SDG&E issued $750 million of 2.950% Green First Mortgage Bonds, Series WWW, due 08/15/2051. In addition, on 08/16/2021, SDG&E paid off $350 million of 3.000% First Mortgage Bonds, Series JJJ.

During the fourth quarter of 2021, SDG&E issued commercial paper with an average daily balance of $174.8 million and a maximum outstanding balance of $400.8 million. The year‐end balance was $400.8 million.

None

On 09/01/2021, SDG&E employees represented by the International Brotherhood of Electrical Workers (IBEW) Local 465 received a negotiated base rate increase of 3.75%, affecting 1471 employees:

Total annualized base wages for represented employees in 2021 is $1.43 million above 2020 base wages.

Total annualized wages for represented employees including overtime in 2021 is $1.41 million above 2020 wages including overtime.

Total annualized wage increases were lower due to minimal time-and-one-half costs as a continuing effect of temporary wage concessions made related to the 2020 Pandemic Plan.

Total annualized wage increases were lower due to a decrease in double time pay related to the scheduled 16-hour workday concession within the 2020 Pandemic Plan

On 09/03/2021, SDG&E reached agreement with IBEW Local 465 on the Lineman Attraction and Retention Letter of Understanding. The intent of the agreement is to attract and retain qualified Journeyman Lineman to SDGE. Approximately 235 electric-side employees each received a retention payment of $22k on 10/27/2021. Total overall cost of this payment, the first of two such payments, was $5.17 million.

Please refer to the Legal Proceedings sections of the Notes to the Financial Statements on page 123.56.

None

Please refer to the Notes to the Financial Statements beginning on page 123.1.

Changes in Officers:


Name	Title	Effective Date

Kevin C. Geraghty	Chief Safety Officer (in addition to existing title of Senior Vice President – Electric Operations)	Appointed, 01/01/2021

Eugene W. Mitchell	Vice President – External Affairs	Resigned, 06/25/2021

Scott B. Crider	Chief Customer Officer to Senior Vice President of Customer Services and External Affairs	Changed, 06/26/2021

Estela M. de Llanos	Vice President – Clean Transportation, Sustainability and Chief Environmental Officer to Vice President of Energy Procurement and Sustainability; designated Chief Environmental Officer and Chief Sustainability Officer	Changed, 07/10/2021

Miguel Romero	Vice President – Energy Supply to Vice President of Advanced Energy Innovation	Changed, 07/10/2021

Changes in Directors:


Name	Title	Effective Date

Trevor I. Mihalik	Director	Resigned, 03/23/2021

There have been no material changes in SDG&E's stock ownership or voting power.

N/A

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	25,093,206,634	22,911,869,746
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	1,670,246,956	1,699,907,204
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		26,763,453,590	24,611,776,950
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	(a) 8,253,275,451	7,688,614,673
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		18,510,178,139	16,923,162,277
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		18,510,178,139	16,923,162,277
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		6,003,644	6,027,761
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		326,050	326,050
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	110,647,029	83,449,123
24	OtherInvestments Other Investments (124)
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)		1,011,945,076	1,018,560,122
29	SpecialFunds Special Funds (Non Major Only) (129)
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)		52,855,769	96,188,239
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		1,181,125,468	1,203,899,195
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		24,919,379	261,589,340
36	SpecialDeposits Special Deposits (132-134)
37	WorkingFunds Working Fund (135)			500
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		690,440,956	545,017,728
41	OtherAccountsReceivable Other Accounts Receivable (143)		85,822,400	142,671,640
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		44,281,142	55,474,405
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)			309,614
45	FuelStock Fuel Stock (151)	227
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227
47	Residuals Residuals (Elec) and Extracted Products (153)	227
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	132,881,569	141,897,325
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	123,916,690	196,438,887
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	110,647,029	83,449,123
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)		318,197	371,661
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)		10,519	6,960
57	Prepayments Prepayments (165)		(b) 157,657,818	(c) 125,338,625
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)		2,426,084	2,463,633
60	RentsReceivable Rents Receivable (172)
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		85,445,637	83,866,636
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)		32,854,971	32,679,971
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		111,235,687	152,068,927
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)		52,855,769	96,188,239
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		1,240,145,967	1,449,609,680
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		44,096,807	39,351,544
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	2,592,280,895	2,398,495,226
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		311,787	1,338,961
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		75,907	195,364
77	TemporaryFacilities Temporary Facilities (185)		808,960	69,702
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	371,285,065	426,356,105
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		6,471,198	7,746,378
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	121,184,972	108,426,484
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		3,136,515,591	2,981,589,036
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		24,067,965,165	22,558,260,188

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility

Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking

Accumulated Provision for Depreciation & Amortization Classified

under FERC Seven Factor Test

In Accordance with Guidelines in FERC Order 888


			Accumulated Provision
Electric
Intangible Plant			173,963,956
Steam Production Plant			305,885,272
Other Production Plant			272,588,028
Transmission Plant			1,635,135,373
Distribution Plant			3,606,168,212
General Plant			219,537,534

Ratemaking Electric			6,213,278,375

Nuclear Decommissioning			1,011,036,365
ASC 410 (FAS 143 and FIN 47) - Electric			(1,018,731,937)
Capital Leases A/D			90,279,107
Leased to Others- Citizens A/D (Sunrise)			29,238,086
Leased to Others- Citizens A/D (SX-PQ)			2,234,053
Cuyamaca Permanent Adjustment			17,855,747

Total Electric			6,345,189,796

Ratemaking Gas			1,161,217,848
FIN 47 - Gas			(215,090,648)

Total Gas			946,127,200

Ratemaking Common			857,931,943
FIN 47 - Common			2,922,489
Capital Lease A/D			101,104,023

Total Common			961,958,455

Total Accumulated Provision EOQ 12/2021			8,253,275,451

Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production			293,178,925

Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production			284,106,681

Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant			1,544,320,791

(b) Concept: Prepayments

The 13-month Average Electric Prepayments for 2021 is $104,600,472.

(c) Concept: Prepayments

The 13-month Average Electric Prepayments for 2020 is $93,697,406.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	291,458,395	291,458,395
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)		591,282,978	591,282,978
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	802,165,368	802,165,368
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b	24,605,640	24,605,640
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	6,598,399,584	6,079,146,682
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	10,117,040	10,034,102
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		8,248,583,645	7,729,413,681
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	6,417,859,000	6,053,573,000
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		16,893,710	13,172,642
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		6,400,965,290	6,040,400,358
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		1,400,890,005	1,324,389,008
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		24,801,946	27,160,254
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		29,490,029	98,468,088
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)			1
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		11,316,894	42,363,865
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		889,835,240	875,839,212
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		2,356,334,114	2,368,220,426
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)		775,767,324	200,000,000
38	AccountsPayable Accounts Payable (232)		631,812,212	593,050,722
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		96,613,566	63,664,468
41	CustomerDeposits Customer Deposits (235)		39,847,594	65,802,220
42	TaxesAccrued Taxes Accrued (236)	262	9,883,625	(a) 14,595,365
43	InterestAccrued Interest Accrued (237)		50,435,589	46,363,708
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		9,116,331	9,398,357
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		237,466,246	302,751,975
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		56,606,669	52,796,607
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		32,605,788	75,094,995
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		11,316,894	42,363,865
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		1,928,838,050	1,381,154,552
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)		119,826,334	111,420,524
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	13,106,071	13,377,869
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	444,594,052	431,442,573
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	2,169,772,983	2,357,732,274
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,944,133,637	1,834,966,327
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		441,810,989	290,131,604
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		5,133,244,066	5,039,071,171
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		24,067,965,165	22,558,260,188

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: TaxesAccrued

Note 1:

Ad Valorem taxes are allocated based on type of assets in each taxing jurisdiction.

Note 2:

Sales and Use taxes are allocated based on the Common Allocation Factor.

Sales and Use tax adjustments in column "f" are to adjust carry forward balances from last year.

Note 3:

State and Franchise Tax and Federal Income Tax are charged to departments based on total taxable income generated by each department.

Note 4:

Retirement, Unemployment, and Medicare taxes are charged to departments as a percentage of total taxable labor charged.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF INCOME
Quarterly Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	(a) 6,060,135,745	(f) 5,716,764,976			5,212,753,006	5,015,890,723	841,518,933	697,643,488	(j) 5,863,806	(n) 3,230,765
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	(b) 3,491,009,710	(g) 3,237,591,294			2,971,678,731	2,824,080,272	521,624,560	416,891,085	(k) 2,293,581	(o) 3,380,063
5	MaintenanceExpense Maintenance Expenses (402)	320	272,403,394	291,139,577			239,806,965	261,193,755	32,596,428	29,945,822
6	DepreciationExpense Depreciation Expense (403)	336	755,566,306	685,671,419			659,495,924	603,293,250	91,478,822	78,484,751	(l) 4,591,560	(p) 3,893,418
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	109,656,852	93,924,593			86,569,957	73,801,234	23,086,894	20,123,359
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336	15,744	15,744			15,744	15,744
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		4,676,982	3,801,994			2,856,130	2,290,749	1,820,851	1,511,245
13	RegulatoryCredits (Less) Regulatory Credits (407.4)
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	205,954,128	186,629,503			174,916,236	158,923,105	29,900,883	26,784,120	(m) 1,137,009	(q) 922,278
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	46,370,869	133,332,973			53,377,736	130,986,812	7,006,866	2,346,161
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	18,234,485	39,767,865			22,323,632	41,331,754	4,089,148	1,563,889
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	341,570,424	259,864,642			311,685,673	237,832,617	29,884,752	22,032,025
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	194,599,724	229,531,073			181,263,576	210,267,707	13,336,147	19,263,366
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	271,798	1,050,480			271,798	215,516		1,265,996
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		5,050,587,372	4,701,158,051			4,341,191,354	4,123,697,101	705,961,029	576,025,317	3,434,988	1,435,633
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		1,009,548,373	1,015,606,925			871,561,652	892,193,622	135,557,904	121,618,171	2,428,818	1,795,132
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		9,029,242	6,934,453
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		37,363	38,948
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		7,183,019	13,668,960
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		(c) 81,462,879	(h) 79,095,805
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		90,738	411,200
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		2,015,252
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		81,760,009	86,280,460
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)
44	MiscellaneousAmortization Miscellaneous Amortization (425)		250,048	250,048
45	Donations Donations (426.1)		16,572,860	13,530,965
46	LifeInsurance Life Insurance (426.2)		7,593,458	7,555,514
47	Penalties Penalties (426.3)		259,137	5,587,200
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		4,092,624	7,169,979
49	OtherDeductions Other Deductions (426.5)		37,912,963	39,572,224
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		51,494,174	58,554,902
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	843,356	766,762
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	11,607,392	12,613,256
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	5,359,962	5,822,969
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	7,695,860	7,765,578
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	1,258,307	1,315,333
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		9,686,445	11,219,218
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		39,952,280	38,944,776
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		237,653,596	233,778,584
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		4,408,152	4,107,085
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		1,275,181	1,449,784
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)
68	OtherInterestExpense Other Interest Expense (431)		11,190,738	15,223,253
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		(d) 24,279,916	(i) 24,499,867
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		230,247,751	230,058,839
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		819,252,902	824,492,862
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		(e) 819,252,902	824,492,862

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OperatingRevenues

Total Operating Revenues excludes amounts associated with interdepartmental transfers.

(b) Concept: OperationExpense

Total Operating Revenues excludes amounts associated with interdepartmental transfers.

(c) Concept: AllowanceForOtherFundsUsedDuringConstruction

Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net

under-collections excluded from the calculation of AFUDC rate, amount to $277.0 million. There was no short-term debt included in the calculation of the AFUDC in 2021.

During the year, the average amount of short-term debt directly related to the use of the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate, amount to $6.6 million.

(d) Concept: AllowanceForBorrowedFundsUsedDuringConstructionCredit

Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net

under-collections excluded from the calculation of AFUDC rate, amount to $277.0 million. There was no short-term debt included in the calculation of the AFUDC in 2021.

During the year, the average amount of short-term debt directly related to the use of the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate, amount to $6.6 million.

(e) Concept: NetIncomeLoss

South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

(f) Concept: OperatingRevenues

Total Operating Revenues excludes amounts associated with interdepartmental transfers.

(g) Concept: OperationExpense

Total Operating Revenues excludes amounts associated with interdepartmental transfers.

(h) Concept: AllowanceForOtherFundsUsedDuringConstruction

Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net under-collections excluded from the calculation of AFUDC rate, amount to $166.0 million. There was no short-term debt included in the calculation of the AFUDC in 2020.

During the year, the use of the waiver for the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate did not cause any benefit.

(i) Concept: AllowanceForBorrowedFundsUsedDuringConstructionCredit

Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net under-collections excluded from the calculation of AFUDC rate, amount to $166.0 million. There was no short-term debt included in the calculation of the AFUDC in 2020.

During the year, the use of the waiver for the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate did not cause any benefit.

(j) Concept: OperatingRevenues


Eliminates interdepartmental transfers	$	(4,296,617)
Citizens Energy Corporation Sunrise Powerlink Lease Recoveries	10,160,424
	$	5,863,806

(k) Concept: OperationExpense


Eliminates interdepartmental transfers	$	(4,296,617)
Citizens Energy Corporation Operating Expenses	2,003,037
	$	(2,293,581)

(l) Concept: DepreciationExpense


Depreciation expenses related to the Citizens Energy Corporation lease	$	2,836,960
Other	1,754,599
	$	4,591,560

(m) Concept: TaxesOtherThanIncomeTaxesUtilityOperatingIncome


Citizens Energy Corporation Property Tax	$	1,106,661
Citizens Energy Corporation Payroll Tax	30,347
	$	1,137,009

(n) Concept: OperatingRevenues


Eliminates interdepartmental transfers	$	(4,953,159)
Citizens Energy Corporation Sunrise Powerlink Lease Recoveries	8,183,923
	$	3,230,765

(o) Concept: OperationExpense


Eliminates interdepartmental transfers	$	(4,953,158)
Citizens Energy Corporation Operating Expenses	1,573,097
	$	(3,380,063)

(p) Concept: DepreciationExpense


Depreciation expenses related to the Citizens Energy Corporation lease	$	2,836,960
Other	1,056,459
	$	3,893,418

(q) Concept: TaxesOtherThanIncomeTaxesUtilityOperatingIncome


Citizens Energy Corporation Property Tax	$	893,770
Citizens Energy Corporation Payroll Tax	28,508
	$	922,278

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). State the purpose and amount for each reservation or appropriation of retained earnings. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		6,079,146,682	5,454,653,820
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
10.1	AdjustmentsToRetainedEarningsDebit ASU 2018-02 Stranded Tax Effects
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		819,252,902	824,492,862
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock		300,000,000	200,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		300,000,000	200,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		6,598,399,584	6,079,146,682
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		6,598,399,584	6,079,146,682
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENT OF CASH FLOWS
Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	(a) 819,252,902	824,492,862
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	755,566,306	685,671,419
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Unrecovered Plant and Regulatory Study Costs	109,672,596	93,940,337
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Impairment - Disallowed Costs from 2019 GRC FD	1,709,067	1,058,143
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	153,408,253	36,783,811
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	271,798	1,050,480
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	101,036,636	199,928,414
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	19,412,441	9,945,205
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	33,742,383	2,970,245
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	39,878,578	9,766,905
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	166,144,447	93,977,578
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	103,448,946	83,037,378
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	81,462,879	79,095,805
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other: Net (Increase) Decrease in Prepayments and Other	39,594,171	94,119,506
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Net Increase (Decrease) in Accrued Interest and Taxes	10,234,730	21,778,194
18.3	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Wildfire Fund
18.4	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other - Net	18,676,328	21,910,750
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	1,342,815,599	1,319,516,822
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	2,301,019,620	2,020,997,426
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	81,462,879	79,095,805
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	2,219,556,741	1,941,901,621
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies		28,790
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription COLI - Corporate Owned Life Insurance	7,099,977	7,915,112
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Decommissioning Trust Fund Purchase	961,092,059	1,439,145,269
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Decommissioning Trust Fund Sales	961,092,059	1,439,145,269
53.4	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Increase (Decrease) in Customer Advances for Construction	5,420,024	44,858,361
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	2,207,036,740	1,889,099,358
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	745,260,000	1,398,076,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other: LTD Issuance Cost	7,762,644	10,654,000
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other: Equity Contribution from Sempra Energy
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)	775,767,324	200,000,000
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	1,513,264,680	1,587,422,000
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	385,714,000	486,979,000
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Short-Term Debt (Term Loan)	200,000,000
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)		79,768,524
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	300,000,000	200,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	627,550,680	820,674,476
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	236,670,461	251,091,940
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	261,589,840	10,497,900
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	24,919,379	261,589,840

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: NetIncomeLoss

South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

NOTES TO FINANCIAL STATEMENTS

Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

Notes for Statement of Cash Flows:


Supplemental Disclosure of Cash Flow Information:		12/31/2021
Income tax payments, net of		$	66,791,792

Interest payments, net of amounts capitalized		$	402,433,408

Reconciliation of Cash and Cash Equivalents at December 31, 2021:
Account 131	Cash	$	24,919,380
Account 135	Working Funds	—
Account 136	Temporary Cash Investments	—
		$	24,919,380

Supplemental Disclosure of Non-Cash Investing & Financing Activities:

Increase in finance lease (PPA & Fleet and Other Equipment) obligations for investments in PP&E		$	23,302,033
Accrued Capital Expenditures		$	227,738,753
Increase in ARO for investment in PP&E		$	13,968,906

B.Basis of Presentation and Notes to Financial Statements

Beginning on page 123.3 are excerpts from the Sempra (or the parent) Annual Report on Form 10-K for the period ending December 31, 2021, as filed with the SEC on February 25, 2022. The following disclosures contain information in accordance with SEC requirements.

These financial statements, included on pages 110 through 122b of this report, were prepared in accordance with the accounting requirements of FERC as set forth in the applicable Uniform System of Accounts and published accounting releases. Such requirements and published accounting releases constitute a comprehensive basis of accounting other than U.S. GAAP. The principal differences of this basis of accounting from U.S. GAAP include, but are not necessarily limited to, the accounting for and classification of:

•Certain deferred income taxes and regulatory assets and liabilities

•Certain assets and liabilities between current and non-current

•Certain cost of removal obligations, and property reserves

•Classification of interest and penalties associated with income taxes

•Electricity sales for resale and purchase power expenses

•Certain revenues net of related costs

•Capital lease treatment of certain contracts

•Certain plant in service, accumulated depreciation, and regulatory assets

•Certain pension costs between other income and A&G

•Certain balance sheet treatment for operating lease for U.S. GAAP purposes are reported under Property Under Capital Leases, Amortization and Capital Lease Obligations.

•Certain lease expenses between depreciation, interest expenses, and other line items.

•Software costs relating to cloud computing between prepaid expenses and utility plant

Due to the differences between FERC and U.S. GAAP reporting requirements as mentioned above, certain amounts disclosed in Notes 1-13 may not agree to balances in the FERC financial statements.

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

BASIS OF PRESENTATION

This is a report of SDG&E. SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra Energy. References in this report to “we,” and “our” are to SDG&E, unless otherwise indicated by the context.

Use of Estimates in the Preparation of the Financial Statements

We have prepared our Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

REGULATED OPERATIONS

SDG&E’s accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, SDG&E records regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of:

•the nature of the event giving rise to the assessment

•existing statutes and regulatory code

•legal precedents

•regulatory principles and analogous regulatory actions

•testimony presented in regulatory hearings

•regulatory orders

•a commission-authorized mechanism established for the accumulation of costs

•status of applications for rehearings or state court appeals

•specific approval from a commission

•historical experience

FAIR VALUE MEASUREMENTS

We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:

•quoted forward prices for commodities

•time value

•current market and contractual prices for the underlying instruments

•volatility factors

•other relevant economic measures

Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions.

CASH AND CASH EQUIVALENTS

CREDIT LOSSES

We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable.

We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivables and customer payment patterns, historical and industry trends, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies, pandemics and other factors. We write off financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.

In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, SDG&E is automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.

As we discuss in Note 4, the CPUC authorized SDG&E to track and request recovery of incremental costs, including uncollectible expenses, associated with complying with customer protection measures ordered by the CPUC related to the COVID-19 pandemic.

In connection with a separate CPUC decision addressing residential service disconnections, SDG&E established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP, as we discuss in Note 4.

In 2021, SDG&E applied, on behalf of its customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, SDG&E received and applied the amounts directly to eligible customer accounts to reduce past due balances.

We provide below allowances and changes in allowances for credit losses for trade receivables and other receivables. We record changes in the allowances for credit losses related to Accounts Receivable – Trade in regulatory accounts.


RECEIVABLES – ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019

Allowances for credit losses at January 1	$	69	$	14	$	11
Provisions for expected credit losses	23		65		10
Write-offs	(26)		(10)		(7)
Allowances for credit losses at December 31	$	66	$	69	$	14

Allowances for credit losses are included in the Balance Sheet as follows:


ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019

Accounts receivable – trade, net	$	42	$	55	$	4
Accounts receivable – other, net	22		14		10
Other long-term assets	2		—		—
Total allowances for credit losses	$	66	$	69	$	14

CONCENTRATION OF CREDIT RISK

Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by our credit department and overseen by our risk management committee.

This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:

•prospective counterparties’ financial condition (including credit ratings)

•collateral requirements

•the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty

•downgrade triggers

We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses

INVENTORIES

We value natural gas inventory using the last-in first-out method. As inventories are sold, differences between the last-in first-out valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. We generally value materials and supplies at the lower of average cost or net realizable value.

The components of inventories are as follows:


INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	SDG&E
	2021		2020

Natural gas	$	—	$	—
Materials and supplies	123		104
Total	$	123	$	104

WILDFIRE FUND

In July 2019, the Wildfire Legislation was signed into law. The Wildfire Legislation addresses certain issues related to catastrophic wildfires in the State of California and their impact on electric IOUs. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board.

The Wildfire Legislation provided that SDG&E would not recover the ROE on its first $215 million of fire risk mitigation capital expenditures.

The Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the Wildfire Legislation, subject to certain limitations.

An IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1 billion or the IOU’s required amount of insurance coverage as recommended by the Wildfire Fund’s administrator. Wildfire claims approved by the Wildfire Fund’s administrator will be paid by the Wildfire Fund to the IOU to the extent funds are available. These utilized funds will be subject to review by the CPUC, which will make a determination as to the degree an IOU’s conduct related to an ignition of a wildfire was prudent or imprudent. The Revised Prudent Manager Standard requires that the CPUC apply clear standards when reviewing wildfire liability losses paid when determining the reasonableness of an IOU’s conduct related to an ignition. Under this standard, the conduct under review related to the ignition may include factors within and beyond the IOU’s control, including humidity, temperature and winds. Costs and expenses may be allocated for cost recovery in full or in part. Also, under this standard, an IOU’s conduct will be deemed reasonable if a valid annual safety certification is in place at the time of the ignition, unless a serious doubt is raised, in which case the burden shifts to the utility to dispel that doubt. The IOUs will receive an annual safety certification from the CPUC if they meet various requirements.

If an IOU has maintained a valid annual safety certification, to the extent it is found to be imprudent, claims will be reimbursable by the IOU to the Wildfire Fund up to a cap based on the IOU’s rate base. The aggregate requirement to reimburse the Wildfire Fund over a trailing three calendar year period is capped at 20% of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination. Based on its 2021 rate base, the liability cap for SDG&E is approximately $1.1 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.

In July 2021, the CPUC approved SDG&E’s 2021 Wildfire Mitigation Plan. In July 2021, the CPUC’s Wildfire Safety Division became the OEIS under the California Natural Resources Agency. As successor to the Wildfire Safety Division, the

OEIS maintains the duties and responsibilities of the former Wildfire Safety Division with respect to Wildfire Mitigation Plans. The 2021 Wildfire Mitigation Plan is effective until the OEIS approves a new plan. In December 2021, SDG&E received its 2021 wildfire safety certification from the OEIS, which is valid for 12 months from the issue date.

The Wildfire Fund was initially funded up to $10.5 billion by a loan from the State of California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place on October 1, 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.

The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $7.5 billion. SDG&E’s share was $322.5 million. The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $3 billion over a 10-year period starting in 2019. SDG&E’s share is $129 million. The contributions are not subject to rate recovery.

In a complaint filed in U.S. District Court for the Northern District of California in July 2019, plaintiffs seek to invalidate AB 1054 based on allegations that the legislation violates federal law. The district court and, subsequently, the U.S. Court of Appeals for the Ninth Circuit dismissed the complaint.

Wildfire Fund Asset and Obligation

In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $451.5 million to the Wildfire Fund, measured at present value as of July 25, 2019 (the date by which both Edison and SDG&E opted to contribute to the Wildfire Fund). SDG&E paid its initial shareholder contribution of $322.5 million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from Sempra. SDG&E expects to continue to make annual shareholder contributions of $12.9 million through December 31, 2028. SDG&E accretes the present value of the Wildfire Fund obligation until the liability is settled.

SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. The estimated period of benefit of the Wildfire Fund asset is 15 years and is based on several assumptions, including, but not limited to:

•historical wildfire experience of each IOU in the State of California, including frequency and severity of the wildfires

•the value of property potentially damaged by wildfires

•the effectiveness of wildfire risk mitigation efforts by each IOU

•liability cap of each IOU

•IOU prudency determination levels

•FERC jurisdictional allocation levels

•insurance coverage levels

The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. We periodically evaluate the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.

The following table summarizes the location of balances related to the Wildfire Fund on SDG&E’s Balance Sheet and Statement of Operations.


WILDFIRE FUND
(Dollars in millions)
		December 31,
	Location	2021		2020
Wildfire Fund asset:
Current	Prepaid Expenses	$	29	$	29
Noncurrent	Wildfire Fund	331		363
Wildfire Fund obligation:
Current	Other Current Liabilities	$	13	$	13
Noncurrent	Deferred Credits and Other	64		75
		Years ended December 31,
		2021		2020
Amortization of Wildfire Fund asset	Operation and Maintenance	$	29	$	29
Impairment of Wildfire Fund asset	Operation and Maintenance	3		—
Accretion of Wildfire Fund obligation	Operation and Maintenance	2		2

INCOME TAXES

Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. Investment tax credits from prior years are amortized to income over the estimated service lives of the properties as required by the CPUC.

Under the regulatory accounting treatment required for flow-through temporary differences, we recognize:

▪regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and

▪regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.

When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.

We provide additional information about income taxes in Note 6.

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

SDG&E is required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. Many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. We balance costs and revenues associated with the GHG program through regulatory balancing accounts. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

RENEWABLE ENERGY CERTIFICATES

RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations.

PROPERTY, PLANT AND EQUIPMENT

PP&E is recorded at cost and primarily represents the buildings, equipment and other facilities used to provide natural gas and electric utility services, including construction work in progress. . Our plant costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant includes AFUDC. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.

We discuss assets collateralized as security for certain indebtedness in Note 5.


PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
	December 31,				Depreciation rates for years ended December 31,
	2021		2020		2021		2020		2019

Natural gas operations	$	3,200	$	2,805	2.55	%	2.51	%	2.47	%
Electric distribution	9,471		8,592		3.93		3.90		3.94
Electric transmission(1)	7,577		7,156		3.02		3.10		2.79
Electric generation	2,446		2,440		4.74		4.56		4.50
Other electric	2,100		1,743		7.23		6.92		6.61
Construction work in progress(1)	1,662		1,700		N/A		N/A		N/A
Total	$	26,456	$	24,436

(1)At At December 31, 2021, includes $542 in electric transmission assets and $5 in construction work in progress related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in the Statement of Operations.

Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period, or the remaining term of the site leases, whichever is shortest.


DEPRECIATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
SDG&E	$	865	$	779	$	719


ACCUMULATED DEPRECIATION
(Dollars in millions)
	December 31,
	2021		2020
Accumulated depreciation:
Natural gas operations	$	919	$	870
Electric transmission, distribution and generation(1)	5,489		5,145
Total	6,408		6,015

(1)Includes $292 at December 31, 2021 related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

We finance our construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. We earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from customers over the expected useful lives of the assets.

We capitalize interest costs incurred to finance capital projects that have not commenced planned principal operations.

The table below summarizes capitalized financing costs, comprised of AFUDC and capitalized interest.


CAPITALIZED FINANCING COSTS
(Dollars in millions)
Years ended December 31,
2021		2020		2019
$	106	$	104	$	75

We provide additional information about temporary adjustments to the AFUDC rate calculation in relation to the COVID-19 pandemic in Note 4.

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost using the present value of the obligation at the time the asset is placed into service, and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. We record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.

We have recorded AROs related to various assets, including:

•fuel and storage tanks

•natural gas transmission and distribution systems

•hazardous waste storage facilities

•asbestos-containing construction materials

•nuclear power facilities

•electric transmission and distribution systems

•energy storage systems

•power generation plants

The changes in ARO are as follows:


CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	2021		2020
Balance as of January 1	$	876	$	866
Accretion expense	38		39
Liabilities incurred and acquired	2		—
Payments	(60)		(60)
Revisions(1)	34		31
Balance at December 31	$	890	$	876

(1)SDG&E’s increase in ARO in 2021 includes $22 million due to a revised estimate related to the decommissioning of SONGS, which is offset in noncurrent Regulatory Assets.

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:

•information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and

•the amount of the loss or a range of possible losses can be reasonably estimated.

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:

•certain hedging activities

•changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans

The Statement of Comprehensive Income (Loss) show the changes in the components of OCI. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income.


CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
	Pension and other postretirement benefits		Total accumulated other comprehensive income (loss)
Balance as of December 31, 2018	$	(10)	$	(10)
Adoption of ASU 2018-02	$	(2)	$	(2)
OCI before reclassifications	(5)		(5)
Amounts reclassified from AOCI	1		1
Net OCI	(6)		(6)
Balance as of December 31, 2019	(16)		(16)
OCI before reclassifications(2)	(4)		(4)
Amounts reclassified from AOCI(2)	10		10
Net OCI	6		6
Balance as of December 31, 2020	(10)		(10)
OCI before reclassifications	(1)		(1)
Amounts reclassified from AOCI	1		1
Net OCI	—		—
Balance as of December 31, 2021	$	(10)	$	(10)

(1)All amounts are net of income tax, if subject to tax.

(2)Pension and Other Postretirement Benefits and Total AOCI include $6 in transfers of liabilities from SDG&E to SoCalGas and $3 in transfers of liabilities from SDG&E to Sempra in 2020 related to the nonqualified pension plans.


RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)						Affected line item on Statement of Operations
	Years ended December 31,
	2021		2020		2019
Pension and other postretirement benefits(1):
Amortization of actuarial loss	$	—	$	1	$	—	Other Income, Net
Settlement charges	1		1		1		Other Income, Net
Total before income tax	1		2		1
	—		(1)		—		Income Tax Expense
Net of income tax	$	1	$	1	$	1
Total reclassifications for the period, net of tax	$	1	$	1	$	1

(1)Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).

REVENUES

See Note 3 for a description of significant accounting policies for revenues.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent and litigation expense.

TRANSACTIONS WITH AFFILIATES

We summarize amounts due from and to unconsolidated affiliates in the following table.


AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	December 31,
	2021		2020

Sempra Energy	$	(40)	$	(38)
SoCalGas	(48)		(21)
Various affiliates	(9)		(5)
Total due to unconsolidated affiliates – current	$	(97)	$	(64)
Income taxes due from Sempra Energy(1)	$	19	$	—

(1)SDG&E is included in the consolidated income tax return of Sempra, and its income tax expense is computed as an amount equal to that which would result from having always filed a separate return..

The following table summarizes revenues and cost of sales from unconsolidated affiliates.


REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
Revenues	$	11	$	6	$	6
Cost of Sales	$	103	$	79	$	74

Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of 13 to 20 bps, depending on the loan balance.

SoCalGas provides natural gas transportation and storage services for SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.

SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M.

The natural gas supply for SDG&E’s core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, revenues and costs related to SDG&E are presented net in SoCalGas’ Statements of Operations.

SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the ESJ wind power generation facility. A second 20-year contract between SDG&E and ESJ for up to 108 MW of renewable power supplied from the same facility commenced in January 2022.

RESTRICTED NET ASSETS

The CPUC’s regulation of SDG&E’s capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2021, Sempra could have received combined loans and dividends of approximately $798 million from SDG&E.

The payment and amount of future dividends are at the discretion of SDG&E’s boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from SDG&E:

•The CPUC requires that SDG&E’s common equity ratio be no lower than one percentage point below the CPUC-authorized percentage of its authorized capital structure. The authorized percentage at December 31, 2021 is 52%.

•SDG&E has a revolving credit line that requires it to maintain a ratio of indebtedness to capitalization (as defined in the agreement) of no more than 65%, as we discuss in Note 5.

Based on these restrictions, at December 31, 2021, SDG&E’s restricted net assets were $7.5 billion which could not be transferred to Sempra.

OTHER INCOME, NET

Other Income, Net on the Statement of Operations consists of the following:


OTHER INCOME, NET
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019

Allowance for equity funds used during construction	$	81	$	79	$	56
Non-service component of net periodic benefit (cost) credit	(13)		(20)		(20)
Interest on regulatory balancing accounts, net	6		9		13
Sundry, net	(10)		(16)		(10)
Total	$	64	$	52	$	39

NOTE 2. NEW ACCOUNTING STANDARDS

No recent accounting pronouncements have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.

NOTE 3. REVENUES

The following table disaggregates our revenues from contracts with customers by major service line and market. The majority of our revenue is recognized over time.


DISAGGREGATED REVENUES
(Dollars in millions)
	Year ended December 31, 2021
By major service line:
Utilities	$	5,144
Energy-related businesses	—
Revenues from contracts with customers	$	5,144

By market:
Gas	$	790
Electric	4,354
Revenues from contracts with customers	$	5,144

Revenues from contracts with customers	$	5,144
Utilities regulatory revenues	360
Other revenues	—
Total revenues	$	5,504
	Year ended December 31, 2020
By major service line:
Utilities	$	4,920
Energy-related businesses	—
Revenues from contracts with customers	$	4,920

By market:
Gas	$	692
Electric	4,228
Revenues from contracts with customers	$	4,920

Revenues from contracts with customers	$	4,920
Utilities regulatory revenues	393
Other revenues	—
Total revenues	$	5,313
	Year ended December 31, 2019
By major service line:
Utilities	$	4,820
Energy-related businesses	—
Revenues from contracts with customers	$	4,820

By market:
Gas	$	587
Electric	4,233
Revenues from contracts with customers	$	4,820

Revenues from contracts with customers	$	4,820
Utilities regulatory revenues	106
Other revenues	—
Total revenues	$	4,926

REVENUES FROM CONTRACTS WITH CUSTOMERS

Our revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.

We generally recognize revenues when performance of the promised commodity service is provided to our customers and we invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.

The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.

We exclude sales and usage-based taxes from revenues. In addition, we pay franchise fees to operate in various municipalities and bill these franchise fees to our customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of our ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues

Utilities revenues include the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity.

Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill our customers are based on tariffs set by regulators within the respective state or country. For SDG&E, which follows the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that it bills to customers also include adjustments for previously recognized regulatory revenues.

We recognize revenues based on regulator-approved revenue requirements, which allow us to recover reasonable operating costs and provides the opportunity to realize our authorized rates of return on our investments. While our revenues are not affected by actual sales volumes, the pattern of our revenue recognition during the year is affected by seasonality. We recognize annual authorized revenue for customers using seasonal factors established in applicable proceedings, which generally results in a significant portion of operating revenues being recognized in the third quarter of each year.

We have an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.

Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.

We recognize revenues from the sale of allocated California GHG emissions allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and we have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. We balance costs and revenues associated with the GHG program through regulatory balancing accounts.

Remaining Performance Obligations

We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.

For contracts greater than one year, at December 31, 2021, we expect to recognize revenue related to the fixed fee component of the consideration as shown below.


REMAINING PERFORMANCE OBLIGATIONS(1)
(Dollars in millions)
2022	$	4
2023	4
2024	4
2025	4
2026	4
Thereafter	63
Total revenues to be recognized	$	83

(1)Excludes intercompany transactions.

Contract Balances from Revenues from Contracts with Customers

From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.

Activities within our contract liabilities are presented below.


CONTRACT LIABILITIES
(Dollars in millions)
	2021		2020		2019
Opening balance, January 1	$	(87)	$	(91)	$	—
Revenue from performance obligations satisfied during reporting period	4		4		1
Payments received in advance	—		—		(92)
Balance at December 31(1)	$	(83)	$	(87)	$	(91)

(1)Balances at December 31, 2021, 2020 and 2019 include $4, $4 and $4, respectively, in Other Current Liabilities and $79, $83 and $87, respectively, in Deferred Credits and Other.

Receivables from Revenues from Contracts with Customers

The table below shows receivable balances associated with revenues from contracts with customers on our Balance Sheet.


RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
	December 31,
	2021		2020
Accounts receivable – trade, net	$	715	$	573
Accounts receivable – other, net	9		8
Due from unconsolidated affiliates – current(1)	2		2
Other long-term assets	25		—
Total	$	751	$	583

(1)Amount is presented net of amounts due to unconsolidated affiliates on the Balance Sheet, when right of offset exists.

In connection with the COVID-19 pandemic and at the direction of the CPUC, we implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, we are automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.

In 2021, we applied, on behalf of our customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, we received and applied the amounts directly to eligible customer accounts to reduce past due balances.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS

Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues

Alternative Revenue Programs

We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.

Decoupled revenues. As discussed earlier, the regulatory framework requires SDG&E to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E to use a “decoupling” mechanism, which allows it to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.

Incentive mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California IOUs, under which SDG&E has earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.

Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.

Other Cost-Based Regulatory Recovery

The CPUC and the FERC authorize SDG&E to collect revenue requirements for operating costs and capital related costs (such as depreciation, taxes and return on rate base) from customers, including:

▪costs to purchase natural gas and electricity;

▪costs associated with administering public purpose, demand response, and customer energy efficiency programs;

▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and

▪costs associated with third party liability insurance premiums.

Authorized costs are recovered as the commodity service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.

We discuss balancing accounts and their effects further in Note 4.

NOTE 4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until such time as a related cash expenditure has been made. Upon the occurrence of a cash expenditure associated with a regulatory asset, the related amounts are recoverable through a regulatory account mechanism for which we earn a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate. The periods during which we recognize a regulatory asset while we do not earn a return vary by regulatory asset.


REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	December 31,
	2021		2020

Fixed-price contracts and other derivatives	$	(50)	$	(53)
Deferred income taxes recoverable (refundable) in rates	125		22
Pension and other postretirement benefit plan obligations	(7)		50
Removal obligations	(2,251)		(2,121)
Environmental costs	62		56
Sunrise Powerlink fire mitigation	122		121
Regulatory balancing accounts(1)(2)
Commodity – electric	77		72
Gas transportation	49		35
Safety and reliability	67		67
Public purpose programs	(107)		(158)
2019 GRC retroactive impacts	—		56
Wildfire mitigation plan	178		93
Liability insurance premium	110		79
Other balancing accounts	207		61
Other regulatory assets (liabilities), net(2)	119		72
Total	$	(1,299)	$	(1,548)

(1)At December 31, 2021 and 2020, the noncurrent portion of regulatory balancing accounts – net undercollected was $358 million and $139 million, respectively.

(2)Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.

Regulatory Assets Not Earning a Return

▪Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased

based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within two years.

▪Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E expects to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 6.

▪Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.

▪The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.

▪Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).

▪Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.

▪The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 48-year period.

Regulatory Assets Earning a Return

▪Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2019 GRC FD associated with the period from January 1, 2019 through December 31, 2019 were recovered in rates over a 24-month period that began in January 2020.

Amortization expense on certain regulatory assets for the years ended December 31, 2021, 2020 and 2019 was $5 million, $4 million and $3 million, respectively.

COVID-19 Pandemic Protections

In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, SDG&E is automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.

In 2021, SDG&E applied, on behalf of its customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, SDG&E received and applied the amounts directly to eligible customer accounts to reduce past due balances.

SDG&E has been authorized to track and request recovery of incremental costs associated with complying with customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including costs associated with suspending service disconnections and uncollectible expenses that arise from customers’ failure to pay. We expect to pursue recovery of small and medium-large commercial and industrial customers’ tracked costs in rates in future CPUC proceedings, which recovery is not assured. Uncollectible expenses related to residential customers are recorded in a two-way balancing account as we discuss below.

Disconnection OIR

In June 2020, the CPUC issued a decision to adopt certain customer protections to reduce residential customer disconnections and improve reconnection processes, including, among other things, imposing limitations on service disconnections, elimination of deposit requirements and reconnection fees, establishment of the AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts, and increased outreach and marketing efforts. As permitted by the decision, SDG&E has established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP.

CPUC GRC

The CPUC uses GRCs to set rates designed to allow SDG&E to recover reasonable operating costs and to provide the opportunity to realize authorized rates of return on its investments.

In September 2019, the CPUC issued a final decision in the 2019 GRC approving SDG&E’s test year revenues for 2019 and attrition year adjustments for 2020 and 2021, which was effective retroactively to January 1, 2019. This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities.

The 2019 GRC FD approved a test year 2019 revenue requirement of $1,990 million for SDG&E’s combined operations ($1,590 million for its electric operations and $400 million for its natural gas operations).

The increases include separately authorized components for O&M and capital-related costs, as follows:


AUTHORIZED REVENUE REQUIREMENT INCREASES FOR 2020 AND 2021
(Dollars in millions)
	2020 increase from 2019				2021 increase from 2020
	Revenue increase		Percent increase		Revenue increase		Percent increase

O&M	$	20	2.64	%	$	19	2.47	%
Capital-related costs	114		9.74		83		6.47
Total increase	$	134	6.74		$	102	4.83

In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs and SDG&E was directed to file a petition for modification to revise its 2019 GRC to add two additional attrition years, resulting in a transitional five-year GRC period (2019-2023). In May 2021, the CPUC issued a final decision approving SDG&E’s request to continue its authorized post-test year mechanisms for 2022 and 2023. For SDG&E, the decision authorizes revenue requirement increases of $87 million (3.92%) for 2022 and $86 million (3.70%) for 2023.

The 2019 GRC FD approved SDG&E’s establishment of two-way liability insurance premium balancing accounts, including wildfire insurance premium costs based on a specific level of coverage. The 2019 GRC FD also permits SDG&E to seek recovery of additional liability insurance coverage.

The 2019 GRC FD clarified that differences between incurred and forecasted income tax expense due to forecasting differences are not subject to tracking in the income tax expense memorandum account beginning in 2019. SDG&E previously recorded regulatory liabilities, inclusive of interest, associated with the 2016 through 2018 tracked forecasting differences of $86 million. In April 2020, the CPUC confirmed treatment of the two-way income tax expense memorandum account for these 2016 through 2018 balances, at which time we released these regulatory liability balances to revenues and regulatory interest.

CPUC Cost of Capital

A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base. In December 2019, the CPUC approved the cost of capital and rate structures (shown in the table below) for SDG&E that became effective on January 1, 2020 and will remain in effect through December 31, 2022, subject to the CCM.


CPUC AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE, SUBJECT TO THE CCM

	Authorized weighting		Return on rate base		Weighted return on rate base
Long-Term Debt	45.25	%	4.59	%	2.08	%
Preferred Stock	2.75		6.22		0.17
Common Equity	52.00		10.20		5.30
	100.00	%			7.55	%

The CCM applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (the CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.000% at the end of the measurement period. The index applicable to SDG&E is based on its credit rating. SDG&E’s CCM benchmark rate is 4.498% based on Moody’s Baa- utility bond index. Alternatively, under the CCM, SDG&E is permitted to file a cost of capital application in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole.

For the measurement period ended September 30, 2021, the CCM would trigger for SDG&E because the average Moody’s Baa- utility bond index between October 1, 2020 and September 30, 2021 was 1.17% below SDG&E’s CCM benchmark rate of 4.498%. In August 2021, SDG&E filed an application with the CPUC to update its cost of capital effective January 1, 2022 due to the ongoing effects of the COVID-19 pandemic rather than have the CCM apply. In this application, SDG&E proposed to adjust its authorized capital structure by increasing its common equity ratio from 52% to 54%. SDG&E also proposed to increase its authorized ROE from 10.20% to 10.55% and decrease its authorized cost of debt from 4.59% to 3.84%. As a result, SDG&E’s proposed return on rate base would decrease from 7.55% to 7.46% if such application is approved by the CPUC as filed. SDG&E filed a joint motion with PG&E and Edison to consolidate all three utilities’ cost of capital applications given the overlapping issues of law and fact, which joint motion was granted in October 2021. In December 2021, the CPUC established a proceeding to determine if SDG&E’s cost of capital was impacted by an extraordinary event. If the CPUC finds that there was not an extraordinary event, the CCM would be effective retroactive to January 1, 2022 and would automatically adjust SDG&E’s authorized ROE from 10.20% to 9.62% and adjust its authorized cost of debt to reflect the then current embedded cost and projected interest rate. If the CPUC finds that there was an extraordinary event, it will then determine whether to suspend the CCM for 2022 and preserve SDG&E’s current authorized cost of capital or hold a second phase of the proceeding to set a new cost of capital for 2022. SDG&E expects a final decision in the second half of 2022. In December 2021, the CPUC granted SDG&E the establishment of memorandum accounts effective January 1, 2022 to track any differences in revenue requirement resulting from the interim cost of capital decision expected in 2022.

SDG&E is required to file its next cost of capital application in April 2022 for a January 1, 2023 effective date.

FERC Rate Matters

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.

SDG&E’s TO4 ROE of 10.05% was the basis of SDG&E’s FERC-related revenue recognition until March 2020, when the FERC approved the settlement terms that SDG&E and all settling parties reached in October 2019 on SDG&E’s TO5 filing. The settlement agreement provided for a ROE of 10.60%, consisting of a base ROE of 10.10% plus an additional 50 bps for participation in the California ISO (the California ISO adder). If the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder, SDG&E would refund the California ISO adder as of the refund effective date

(June 1, 2019) if such a refund is determined to be required by the terms of the TO5 settlement. The TO5 term is effective June 1, 2019 and shall remain in effect each calendar quarter until terminated by a notice at least six months before the end of the calendar year. In 2020, SDG&E recorded retroactive revenues of $12 million related to 2019, and additional FERC revenues of $17 million to conclude a rate base matter, net of certain refunds to be paid to CPUC-jurisdictional customers.

Energy Efficiency Program Inquiry

In January 2020, the CPUC issued a ruling seeking comments on a report prepared by its consultant regarding SDG&E’s Upstream Lighting Program for the program year 2017. The CPUC subsequently expanded the scope of the comments to cover the program year 2018. The Upstream Lighting Program was one of SDG&E’s Energy Efficiency Programs designed to produce energy efficiency savings for which SDG&E could earn a performance-based incentive.

Pursuant to the CPUC ruling, intervenors representing ratepayers questioned SDG&E’s management of the program and alleged that certain program expenditures did not benefit the purpose of the program. As a result of the inquiry, SDG&E voluntarily expanded its review to include the program year 2019. Based on this review, SDG&E concluded that some concessions were appropriate, which include refunding certain costs to customers and reducing certain performance-based incentives. Accordingly, in the year ended December 31, 2020, SDG&E reduced revenues by $51 million and recorded a fine of $6 million in Other (Expense) Income, Net, on the Statement of Operations. The after-tax impact for the year ended December 31, 2020 was $44 million. In October 2020, SDG&E executed a settlement agreement with intervenors consistent with these concessions. In September 2021, the CPUC approved the settlement agreement.

NOTE 5. DEBT AND CREDIT FACILITIES

SHORT-TERM DEBT

Committed Line of Credit

At December 31, 2021, SDG&E had an aggregate capacity of $1.5 billion from a committed line of credit, which provides liquidity and support our commercial paper program. Because our commercial paper program is supported by the line of credit, we reflect the amount of commercial paper outstanding, before reductions of any unamortized discounts, and any letters of credit outstanding as a reduction to the available unused credit capacity.


COMMITTED LINE OF CREDIT
(Dollars in millions)
		At December 31, 2021
Borrower	Expiration date of facility	Total facility		Commercial paper outstanding		Amounts outstanding		Available unused credit
SDG&E	May 2024	$	1,500	$	(401)	$	—	$	1,099

The principal terms of our committed line of credit reflected in the table above include the following:

▪The facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.

▪The facility provides for the issuance of $100 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, SDG&E has the right to increase its letter of credit commitment up to $250 million.

▪Borrowings bear interest at a benchmark rate plus a margin that varies with SDG&E’s credit ratings.

▪SDG&E must maintain a ratio of indebtedness to total capitalization (as defined in the credit facility) of no more than 65% at the end of each quarter. At December 31, 2021, SDG&E was in compliance with this ratio under its credit facility.

Uncommitted Letters of Credit

Outside of our credit facility, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements.


UNCOMMITTED LETTERS OF CREDIT
(Dollars in millions)
		December 31, 2021
	Expiration date range	Uncommitted letters of credit outstanding
SDG&E	January 2022 to May 2022	$	15

Term Loan

In June 2021, we entered into a $375 million, 364-day term loan with a maturity date of June 27, 2022. At December 31, 2021, $375 million, net of negligible issuance costs, was outstanding under the term loan. The borrowing bears interest at benchmark rates plus 62.5 bps. The term loan provides SDG&E with additional liquidity outside of its line of credit.

WEIGHTED-AVERAGE INTEREST RATES

The weighted-average interest rates on the total short-term debt at December 31 were as follows:


WEIGHTED-AVERAGE INTEREST RATES

	December 31,
	2021		2020
SDG&E	0.65	%	0.95	%

LONG-TERM DEBT

The following table shows the detail and maturities of long-term debt outstanding:


LONG-TERM DEBT AND FINANCE LEASES
(Dollars in millions)
	December 31,
	2021		2020

First mortgage bonds (collateralized by plant assets):
3% August 15, 2021	$	—	$	350
1.914% payable 2015 through February 2022	17		53
3.6% September 1, 2023	450		450
2.5% May 15, 2026	500		500
6% June 1, 2026	250		250
1.7% October 1, 2030	800		800
5.875% January and February 2034(1)	—		—
5.35% May 15, 2035	250		250
6.125% September 15, 2037	250		250
4% May 1, 2039(1)	—		—
6% June 1, 2039	300		300
5.35% May 15, 2040	250		250
4.5% August 15, 2040	500		500
3.95% November 15, 2041	250		250
4.3% April 1, 2042	250		250
3.75% June 1, 2047	400		400
4.15% May 15, 2048	400		400
4.1% June 15, 2049	400		400
3.32% April 15, 2050	400		400
2.95% August 15, 2051	750		—
	6,417		6,053
Finance lease obligations:
Purchased-power contracts	1,217		1,237
Other	57		39
	1,274		1,276
	7,691		7,329
Current portion of long-term debt	(49)		(411)
Unamortized discount on long-term debt	(17)		(13)
Unamortized debt issuance costs	(44)		(39)
Total	7,581		6,866

(1)Callable long-term debt not subject to make-whole provisions


MATURITIES OF LONG-TERM DEBT(1)
(Dollars in millions)
2022	$	17
2023	450
2024	—
2025	—
2026	750
Thereafter	5,200
Total	$	6,417

(1)Excludes finance lease obligations, discounts, and debt issuance costs.

SDG&E does not have unsecured long-term obligations at December 31, 2021.

Callable Long-Term Debt

At our option, certain debt at December 31, 2021 is callable subject to premiums:


CALLABLE LONG-TERM DEBT
(Dollars in millions)
Not subject to make-whole provisions	$	—
Subject to make-whole provisions	6,417

First Mortgage Bonds

We issue first mortgage bonds secured by liens on our utility plant assets. We may issue additional first mortgage bonds if in compliance with the provisions of our bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $7.3 billion at December 31, 2021.

In August 2021, we issued $750 million of 2.95% green first mortgage bonds maturing in 2051 and received proceeds of $737 million, net of debt discount, underwriting discounts and debt issuance costs of $13 million. We intend to use the net proceeds to finance or refinance eligible projects that fall into one or more of the following categories: climate change adaptation, clean energy solutions and clean transportation.

Other Long-Term Debt

On February 18, 2022, we entered into a $400 million, two-year term loan with a maturity date of February 18, 2024. We may request up to three borrowings for an aggregate amount of $400 million through May 18, 2022. On February 18, 2022, we borrowed $200 million. The borrowing bears interest at benchmark rates plus 62.5 bps. The margin is based on our long-term senior unsecured credit rating.

NOTE 6. INCOME TAXES

We provide our calculations of ETRs in the following table.


INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2021			2020			2019
Income tax expense	$	201		$	190		$	171
Income before income taxes	$	1,020		$	1,014		$	938
Effective income tax rate	20		%	19		%	18		%

For SDG&E, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment:

▪repairs expenditures related to a certain portion of utility plant fixed assets

▪the equity portion of AFUDC, which is non-taxable

▪a portion of the cost of removal of utility plant assets

▪utility self-developed software expenditures

▪depreciation on a certain portion of utility plant assets

▪state income taxes

We present in the table below reconciliations of net U.S. statutory federal income tax rates to our ETRs.


RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES

	Years ended December 31,
	2021		2020		2019
U.S. federal statutory income tax rate	21	%	21	%	21	%
State income taxes, net of federal income tax benefit	5		5		6
Depreciation	3		3		3
Excess deferred income taxes outside of ratemaking	—		—		(3)
Self-developed software expenditures	(1)		(4)		(3)
Amortization of excess deferred income taxes	(2)		(1)		(1)
Allowance for equity funds used during construction	(2)		(2)		(1)
Repairs expenditures	(4)		(3)		(3)
Other, net	—		—		(1)
Effective income tax rate	20	%	19	%	18	%

The remeasurement of deferred income tax balances in December 2017, as a result of the TCJA, resulted in excess deferred income taxes that previously had been collected from ratepayers at the higher rate. In a January 2019 decision, the CPUC directed certain excess deferred income tax balances generated by activities outside of ratemaking be allocated to shareholders rather than ratepayers. As a result, in 2019, SDG&E recorded income tax benefits of $31 million from the release of a portion of the regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances.

The table below summarizes the effects of the TCJA remeasurement at December 31, 2017, by FERC account and jurisdiction.


TCJA REMEASUREMENT – REDUCTION TO DEFERRED INCOME TAX BALANCES
(Dollars in millions)
	Year ended December 31, 2017
	FERC ACs 182.3/254		FERC AC 190(1)(2)		FERC AC 282		FERC AC 283(3)		Total Deferred		FERC AC 410(Exp)
FERC	$	599	$	5	$	(421)	$	(183)	$	(599)	$	—
CPUC	829		6		(474)		(361)		(829)		—
Shareholder	—		2		26		—		28		(28)
Total	$	1,428	$	13	$	(869)	$	(544)	$	(1,400)	$	(28)

(1)Since the table is summarizing a reduction to the net deferred income tax liability balance, the decrease to the 190 deferred tax asset account in this table is shown as positive.

(2)Does not include the net operating loss deferred tax asset related to FERC Transmission.

(3)Account 283 includes approximately $500 million of gross-up required under ASC 740 on flow-through deferred taxes and gross-up on excess deferred taxes.

In the first quarter of 2018, we made a $38 million true-up primarily related to the gross-up on flow-through deferred taxes required under ASC 740, Income Taxes. This resulted in additional reduction of deferred tax liabilities and an increase in net regulatory liabilities. In the first quarter of 2019, we reclassed $31 million of certain excess deferred taxes out of regulatory liabilities and into Shareholder, because these items were not related to plant in service nor were they part of the reduction to rate base for accumulated deferred income taxes.

The table below represents the amount of protected and unprotected excess deferred income taxes related to plant in service (excluding gross-up) as of December 31, 2021, 2020, 2019, 2018 and 2017.


TOTAL COMPANY EXCESS DEFERRED INCOME TAXES FOR PLANT IN SERVICE(1)
(Dollars in millions)
	Year ended December 31
	2021		2020		2019		2018		2017
FERC - Protected	$	366	$	371	$	380	$	382	$	384
CPUC - Protected	441		450		457		463		469
FERC - Unprotected(2)	(7)		6		1		3		6
CPUC - Unprotected(3)	(118)		(117)		(118)		(120)		(122)
Total	$	682	$	710	$	720	$	728	$	737

(1)Does not include the net operating loss deferred tax asset related to FERC Transmission.

(2)Includes prior year true-up to excess deferred income tax balance and an adjustment to reclass certain Transmission-related excess deferred income taxes between Protected and Unprotected pursuant to FERC Order 864.

(3)Includes prior true-up to excess deferred income tax balance.

For plant in service, we use the Average Rate Assumption Method (ARAM) to amortize the excess deferred income taxes over the book life of the underlying property. During 2019, we received a final decision from the CPUC in our general rate case directing us to use straight-line amortization over a six-year period for certain unprotected items, and allowing us to track any differences between using ARAM and using the six-year straight-line amortization for these unprotected items. During 2021, we decided we would no longer contest the CPUC’s treatment of these unprotected items, which resulted in increased amortization in 2021. The CPUC decision also allowed us to track differences related to the inclusion of new cost of removal accruals in the ARAM calculation. As of December 31, 2021, we have not received a final regulatory order from the FERC regarding how customer rates should be reduced for excess deferred income taxes. Future potential regulatory orders and IRS guidance could impact our classification of protected and unprotected amounts indicated above, as well as the inclusion of new cost of removal accruals in the ARAM calculation.

Under ARAM, we reduced our regulatory liability related to excess deferred income taxes by $19 million, $10 million, $8 million, and $9 million in 2021, 2020, 2019, and 2018 respectively, excluding gross-up. The reduction in the excess deferred income tax regulatory liability (FERC AC 254) was offset against deferred income taxes (FERC AC 411.1). The table below reflects these adjustments for the following FERC accounts as of December 31, 2021, 2020, 2019, and 2018.


ARAM - REGULATORY LIABILITY / DEFERRED INCOME TAXES
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019		2018		Amortization Period
FERC ACs 254/411.1
FERC - Protected	$	3	$	3	$	2	$	2	Book Depreciation Life
CPUC - Protected	8		7		6		6		Book Depreciation Life
FERC - Unprotected	1		2		2		3		Book Depreciation Life
CPUC - Unprotected	7		(2)		(2)		(2)		Book Depreciation Life
Total	$	19	$	10	$	8	$	9

3.0

The components of income tax expense are as follows.


INCOME TAX EXPENSE
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019

Current:
U.S. federal	$	35	$	121	$	35
U.S. state	13		34		31
Total	48		155		66
Deferred:
U.S. federal	99		11		75
U.S. state	54		25		32
Total	153		36		107
Deferred investment tax credits	—		(1)		(2)
Total income tax expense	$	201	$	190	$	171


NOTES TO FINANCIAL STATEMENTS (Continued)

The table below presents the components of deferred income taxes:


DEFERRED INCOME TAXES
(Dollars in millions)
	December 31,
	2021		2020
Deferred income tax liabilities:
Differences in financial and tax bases of utility plant and other assets	$	1,970	$	1,833
Regulatory balancing accounts	323		224
Right-of-use assets – operating leases	52		28
Property taxes	35		34
Other	1		2
Total deferred income tax liabilities	2,381		2,121
Deferred income tax assets:
Tax credits	5		5
Postretirement benefits	—		14
Compensation-related items	12		12
Operating lease liabilities	52		28
Bad debt allowance	16		18
State income taxes	4		8
Accrued expenses not yet deductible	16		14
Other	1		3
Total deferred income tax assets	106		102
Net deferred income tax liability	$	2,275	$	2,019

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:


RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2021		2020		2019
Balance at January 1	$	13	$	12	$	11
Increase in prior period tax positions	1		1		1
Balance at December 31	$	14	$	13	$	12
Of December 31 balance, amounts related to tax positions that if recognized in future years would:
Decrease the effective tax rate(1)	$	(11)	$	(10)	$	(9)
Increase the effective tax rate(1)	1		1		1

(1)Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:


POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
	At December 31,
	2021		2020		2019
Potential resolution of audit issues with various U.S. federal, state and local taxing authorities	$	6	$	6	$	6

Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Statement of Operations. SDG&E accrued negligible amounts for interest expense and penalties at December 31, 2021 and 2020 on the Balance Sheet, and recorded negligible amounts of interest expense and penalties in the Statement of Operations for all periods presented.

INCOME TAX AUDITS

SDG&E is subject to U.S. federal income tax and state income tax and remains subject to examination for U.S. federal tax years after 2017 and state tax years after 2012

NOTE 7. EMPLOYEE BENEFIT PLANS

For our employee benefit plans, we:

•recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;

•measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and

•recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of primarily Sempra and its consolidated subsidiaries.

Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E, which collectively cover all eligible employees, including a member of the Sempra board of directors who was a participant in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

Sempra also has PBOP plans, including separate plans for SDG&E, which collectively cover all employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits.

Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $567 million and $512 million at December 31, 2021 and 2020, respectively.

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Benefit Plan Amendments Affecting 2019

In 2019, certain executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. This was treated as a plan amendment and increased the recorded pension liability by $3 million in 2019.

Benefit Obligations and Assets

The following table provides a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2021 and 2020, and a statement of the funded status at December 31, 2021 and 2020:


PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS

(Dollars in millions)
	Pension benefits				Other postretirement benefits
	2021		2020		2021		2020
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	913	$	895	$	193	$	177
Service cost	35		31		5		4
Interest cost	25		30		5		6
Contributions from plan participants	—		—		7		8
Actuarial (gain) loss	(2)		37		(3)		17
Plan amendments	—		—		—		—
Benefit payments	(17)		(18)		(19)		(20)
Settlements	(69)		(52)		—		—
Transfer of liability from other plans	—		(10)		—		1
Net obligation at December 31	885		913		188		193

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	819		739		213		197
Actual return on plan assets	73		94		(5)		26
Employer contributions	53		52		1		1
Contributions from plan participants	—		—		7		8
Benefit payments	(17)		(18)		(19)		(20)
Settlements	(69)		(52)		—		—
Transfer of assets from other plans	—		4		—		1
Fair value of plan assets at December 31	859		819		197		213
Funded status at December 31	$	(26)	$	(94)	$	9	$	20
Net recorded (liability) asset at December 31	$	(26)	$	(94)	$	9	$	20

Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and Other Postretirement Benefit Plans” and updates to census data. In 2021, 2020 and 2019, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. We have incorporated these assumptions, adjusted for the Sempra companies’ actual mortality experience, in our calculations for each of those years.

▪Actuarial gains in pension plans in 2021 were driven primarily by an increase in discount rates. These actuarial gains were partially offset by actuarial losses due to an increase in the interest crediting rate for the cash balance plans due to updated census data.

▪Actuarial gains in PBOP plans in 2021 were driven primarily by an increase in discount rates.

Net Assets and Liabilities

The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. SDG&E recognizes realized and unrealized investment gains and losses during the current year.

We use the 10% corridor accounting method. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The 10% corridor accounting method helps mitigate volatility of net periodic benefit costs from year to year.

Defined benefit pension and other postretirement plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. We record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.

We record annual pension and other postretirement net periodic benefit costs equal to the contributions to our qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:

▪a minimum required funding amount as required by the IRS;

▪the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or

▪beginning January 1, 2019 and for the duration of the 2019 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a 14-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2019, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.

The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.

The net (liability) asset is included in the following categories on the Balance Sheet at December 31:


PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	2021		2020		2021		2020
Noncurrent assets	$	—	$	—	$	9	$	20
Current liabilities	(1)		(2)		—		—
Noncurrent liabilities	(25)		(92)		—		—
Net recorded (liability) asset	$	(26)	$	(94)	$	9	$	20

Amounts recorded in AOCI at December 31, net of income tax effects and amounts recorded as regulatory assets, are as follows:


AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension benefits
	2021		2020
Net actuarial loss	$	(9)	$	(8)
Prior service cost	$	(1)	$	(2)
Total	$	(10)	$	(10)

The following table shows the obligations of funded pension plan with benefit obligations in excess of plan assets. At December 31, 2021, the assets for SDG&E’s funded pension plan exceeded the plan’s obligations.


OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	2020
Projected benefit obligation	$	887
Accumulated benefit obligation	834
Fair value of plan assets	819

The following table shows SDG&E’s obligations of unfunded pension plans at December 31:


OBLIGATIONS OF UNFUNDED PENSION PLANS
(Dollars in millions)
	2021		2020
Projected benefit obligation	$	26	$	26
Accumulated benefit obligation	22		22

SDG&E has a funded other postretirement benefit plan. At December 31, 2021, the assets for SDG&E’s other postretirement benefit plan exceeded the plan’s obligations.

Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:


NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2021		2020		2019		2021		2020		2019
NET PERIODIC BENEFIT COST
Service cost	$	35	$	31	$	30	$	5	$	4	$	4
Interest cost	25		30		34		5		6		7
Expected return on assets	(50)		(49)		(38)		(10)		(10)		(11)
Amortization of:
Prior service cost	1		2		3		—		—		2
Actuarial loss (gain)	2		3		11		(2)		(3)		(2)
Settlement charges	6		—		—		—		—		—
Net periodic benefit cost (credit)	19		17		40		(2)		(3)		—
Regulatory adjustment	34		38		14		2		3		—
Total expense recognized	53		55		54		—		—		—

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss	1		6		5		—		—		—
Prior service cost	—		—		2		—		—		—
Transfer of actuarial gain	—		(7)
Transfer of prior service credit	—		(5)		—		—		—		—
Amortization of actuarial loss	—		(1)		—		—		—		—
Amortization of prior service cost	(1)		(1)		(1)		—		—		—
Total recognized in OCI	—		(8)		6		—		—		—
Total recognized in net periodic benefit cost and OCI	$	53	$	47	$	60	$	—	$	—	$	—

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

We develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.

Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.

Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.

The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:


WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION
AT DECEMBER 31
	Pension benefits				Other postretirement benefits
	2021		2020		2021		2020
Discount rate	2.99	%	2.73	%	3.05	%	2.85	%
Interest crediting rate(1)(2)	1.94		1.62		1.94		1.62
Rate of compensation increase	3.50-10.00		2.70-10.00		3.50-10.00		2.70-10.00

(1)Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2)Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts.


WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
YEARS ENDED DECEMBER 31
	Pension benefits						Other postretirement benefits
	2021		2020		2019		2021		2020		2019

Discount rate	2.73	%	3.44	%	4.29	%	2.85	%	3.55	%	4.30	%
Expected return on plan assets	6.25		7.00		7.00		4.81		5.51		6.92
Interest crediting rate(1)(2)	1.62		2.28		3.36		1.62		2.28		3.36
Rate of compensation increase	2.70-10.00		2.70-10.00		2.00-10.00		2.70-10.00		2.70-10.00		2.00-10.00

(1)Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2)Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts.

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:


ASSUMED HEALTH CARE COST TREND RATES
AT DECEMBER 31
	Other postretirement benefit plans
	Pre-65 retirees						Retirees aged 65 years and older
	2021		2020		2019		2021		2020		2019
Health care cost trend rate assumed for next year	6.00	%	6.00	%	6.25	%	4.75	%	4.75	%	4.75	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	4.75	%	4.75	%	4.75	%	4.50	%	4.50	%	4.50	%
Year the rate reaches the ultimate trend	2025		2025		2025		2022		2022		2022

Plan Assets

Investment Allocation Strategy for Sempra’s Pension Master Trust

Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. Sempra maintains additional trusts, as we discuss below, including for certain of SDGE’s PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra.

The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ target asset allocations are:

▪31% domestic equity

▪21% international equity

▪21% long credit

▪10% diversified real assets

▪10% return-seeking credit

▪5% ultra-long duration government securities

▪2% other diversifying assets

The asset allocation of the plans is reviewed by Sempra’s Plan Funding Committee and Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:

▪long-term cost

▪variability and level of contributions

▪funded status

▪a range of expected outcomes over varying confidence levels

This allocation results in a 74% target allocation to return-seeking assets and a 26% target allocation to risk-mitigating assets. We maintain asset allocations at strategic levels with reasonable bands of variance.

In accordance with the Sempra pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.

Rate of Return Assumption

The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 6.75% expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 4% and 12% on return-seeking assets and between 1% and 4% for risk-mitigating assets. Certain trusts that hold assets for the SDG&E other postretirement benefit plan are subject to taxation, which impacts the expected after-tax return on assets in the plan.

Concentration of Risk

Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.

Investment Strategy for SDG&E’s Other Postretirement Benefit Plans

SDG&E’s PBOP plans are funded by cash contributions from SDG&E and its current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Certain assets of SDG&E’s PBOP plans are held in the pension master trust, which invests a portion of the assets in completion portfolios that aim to reduce interest rate risk, thereby resulting in an overall target allocation of 38% to return-seeking assets and 62% to risk-mitigating assets for these well-funded plans. SDG&E’s assets held in other Voluntary Employee Beneficiary Association trusts are invested in accordance with a de-risking glidepath that reduces the assets’ exposure to risk as the trusts become better funded. These specific allocations are periodically reviewed to help ensure that plan assets are best positioned to meet plan obligations.

Fair Value of Pension and Other Postretirement Benefit Plan Assets

We classify the investments in the trusts for SDG&E’s PBOP plans based on the fair value hierarchy, except for certain investments measured at NAV.

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.

Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Venture Capital Funds and Real Estate Funds – These funds consist of investments in venture capital funds and real estate funds that are held by limited partnerships or similar private entities following various investment strategies. The value is determined based on the NAV of our proportionate ownership interest in the entity.

Derivative Financial Instruments – Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.

SDG&E holds a proportionate share of investment assets in the pension master trust at Sempra. The fair values of our pension plan assets by asset category are as follows:


FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2021
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Cash and cash equivalents	$	18	$	—	$	18
Equity securities:
Domestic	844		5		849
International	384		1		385
Registered investment companies
Domestic	204		21		225
International	33		—		33
Fixed income securities:
Domestic government and government agencies	463		24		487
International government bonds	—		11		11
Domestic corporate bonds	—		413		413
International corporate bonds	—		65		65
Other	1		—		1
Total investment assets in the fair value hierarchy	$	1,947	$	540	2,487
Accounts receivable/payable, net					(20)
Investments measured at NAV:
Common/collective trusts					657
Venture capital funds and real estate funds					58
Total investment assets					$	3,182
SDG&E’s proportionate share of investment assets					$	859
SoCalGas’ proportionate share of investment assets					$	2,095
	Fair value at December 31, 2020
	Level 1		Level 2		Total
Sempra Energy Consolidated:
Cash and cash equivalents	$	7	$	—	$	7
Equity securities:
Domestic	931		—		931
International	563		—		563
Registered investment companies
Domestic	151		37		188
International	32		—		32
Fixed income securities:
Domestic government and government agencies	238		34		272
International government bonds	—		13		13
Domestic corporate bonds	—		418		418
International corporate bonds	—		61		61
Other	2		(1)		1
Total investment assets in the fair value hierarchy	$	1,924	$	562	2,486
Accounts receivable/payable, net					13
Investments measured at NAV:
Common/collective trusts					493
Venture capital funds and real estate funds					10
Total investment assets					$	3,002
SDG&E’s proportionate share of investment assets					$	819
SoCalGas’ proportionate share of investment assets					$	1,969

The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SDG&E’s PBOP plan trusts are as follows:


FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2021
	Level 1		Level 2		Total

Equity securities:
Domestic	$	16	$	—	$	16
International	7		—		7
Registered investment companies
Domestic	82		1		83
International	9		—		9
Fixed income securities:
Domestic government bonds	24		1		25
Domestic corporate bonds	—		8		8
Registered investment companies	—		1		1
Total investment assets in the fair value hierarchy	138		11		149
Accounts receivable/payable, net					(1)
Investments measured at NAV – Common/collective trusts					49
Total investment assets					$	197
	Fair value at December 31, 2020
	Level 1		Level 2		Total
Equity securities:
Domestic	$	17	$	—	$	17
International	11		—		11
Registered investment companies
Domestic	69		7		76
International	11		—		11
Fixed income securities:
Domestic government bonds	38		2		40
Domestic corporate bonds	—		8		8
Registered investment companies	—		1		1
Total investment assets in the fair value hierarchy	146		18		164
Accounts receivable/payable, net					(2)
Investments measured at NAV – Common/collective trusts					51
Total investment assets					$	213

Future Payments

We expect to contribute the following amounts to our pension and PBOP plans in 2022:


EXPECTED CONTRIBUTIONS
(Dollars in millions)
Pension plans	$	52
Other postretirement benefit plans	1

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.


EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Pension benefits		Other postretirement benefits
2022	$	71	$	9
2023	69		10
2024	66		10
2025	65		10
2026	59		10
2027-2031	275		48

SAVINGS PLANS

Sempra, SDG&E and SoCalGas offer trusteed savings plans to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.

Employer contributions to the SDG&E savings plans were as follows:


EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	2021		2020		2019
SDG&E	$	18	$	16	$	15

The market value of Sempra common stock held by the savings plans at Sempra, SDG&E and SoCalGas was $1.0 billion and $1.1 billion at December 31, 2021 and 2020, respectively.

NOTE 8. SHARE-BASED COMPENSATION

SEMPRA ENERGY EQUITY COMPENSATION PLANS

Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including:

•nonqualified stock options

•incentive stock options

•restricted stock awards

•restricted stock units

•stock appreciation rights

•performance awards

•stock payments

•dividend equivalents

Eligible SDG&E employees participate in Sempra’s share-based compensation plans as a component of their compensation package.

In the three years ended December 31, 2021, Sempra had the following types of equity awards outstanding:

▪Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire 10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

▪Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra common stock at the end of three-year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. Sempra uses long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop its targets for awards that vest based on EPS growth. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

•Up to an additional 100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.

•For awards granted in 2016 and certain awards granted in 2017 and 2018 that vest based on Sempra’s total return to shareholders, a modifier adds 20% to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra and reduces the award’s payout by 20% for performance in the bottom quartile. However, in no event will more than an additional 100% of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices.

If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis.

▪Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably over three-year service periods (for awards granted after 2018), or at the end of three-year (for awards granted during 2016 through 2018) or four-year service periods (for awards granted prior to 2015). These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.

For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.

SHARE-BASED AWARDS AND COMPENSATION EXPENSE

At December 31, 2021, 5,986,241 of Sempra common shares were authorized and available for future grants of share-based awards. Sempra’s practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

Sempra measures and recognizes compensation expense for all share-based payment awards made to its employees and directors based on estimated fair values on the date of grant. Sempra recognizes compensation costs net of an estimated forfeiture rate (based on historical experience) and recognizes the compensation costs for nonqualified stock options and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, Sempra recognizes additional paid in capital as it recognizes the compensation expense associated with the awards. Sempra recognizes in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.

SDG&E records an expense for the plans to the extent that its employees participate in the Sempra plans and/or SDG&E is allocated a portion of the Sempra plans’ corporate staff costs. For SDG&E, total share-based compensation expense for share-based awards was comprised as follows:


SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
Share-based compensation expense, before income taxes	$	10	$	11	$	10
Income tax benefit	(3)		(3)		(3)
	$	7	$	8	$	7

Capitalized share-based compensation cost	$	5	$	7	$	6
Excess income tax deficiency	$	(1)	$	(3)	$	1

SEMPRA NONQUALIFIED STOCK OPTIONS

Sempra uses a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires it to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2021, 2020 and 2019, Sempra’s board of directors granted 222,620, 154,860 and 261,075 nonqualified stock options, respectively, that are exercisable over a three-year period. The weighted-average per-

share fair value for options granted was $19.07, $19.76 and $13.20 in 2021, 2020 and 2019, respectively. To calculate this fair value, Sempra used the Black-Scholes model with the following weighted-average assumptions:


KEY ASSUMPTIONS FOR STOCK OPTIONS GRANTED

	Year ended December 31,
	2021		2020
Stock price volatility	26.57	%	18.78	%
Expected term	5.36 years		5.34 years
Risk-free rate of return	0.41	%	1.68	%
Annual dividend yield	3.38	%	2.60	%

The following table shows a summary of nonqualified stock options at December 31, 2021 and activity for the year then ended:


NONQUALIFIED STOCK OPTIONS

	Common shares under options	Weighted- average exercise price		Weighted- average remaining contractual term (in years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2021	365,395	$	120.93
Granted	222,620	$	123.80
Exercised	(50,671)	$	106.76
Outstanding at December 31, 2021	537,344	$	123.45	8.06	$	5

Vested or expected to vest at December 31, 2021	537,344	$	123.45	8.06	$	5
Exercisable at December 31, 2021	152,189	$	118.10	7.27	$	2

The aggregate intrinsic value at December 31, 2021 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised in the last three years was:

▪$1.4 million in 2021

▪$0.4 million in 2020

▪$4 million in 2019

Sempra expects a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.1 years. The weighted-average per-share fair values for nonqualified stock options granted in 2020 and 2019 was $149.12 and $106.76, respectively.

Sempra received cash of $5 million, a negligible amount and $3 million from stock option exercises in 2021, 2020 and 2019, respectively.

SEMPRA RESTRICTED STOCK UNITS

Sempra uses a Monte-Carlo simulation model to estimate the fair value of its RSUs that vest based on Sempra’s total return to shareholders. Its determination of fair value is affected by the historical volatility of the common stock price for Sempra

and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. Below are key assumptions for RSUs granted in the last three years:


KEY ASSUMPTIONS FOR RSUs GRANTED

	Years ended December 31,
	2021		2020		2019
Stock price volatility	33.39	%	16.35	%	17.74	%
Risk-free rate of return	0.16	%	1.55	%	2.46	%

The following table shows a summary of RSUs at December 31, 2021 and activity for the year then ended:


RESTRICTED STOCK UNITS

	Performance-based restricted stock units			Service-based restricted stock units
	Units	Weighted- average grant-date fair value		Units	Weighted- average grant-date fair value
Nonvested at January 1, 2021	893,961	$	121.61	343,577	$	121.59
Granted	323,889	$	133.03	143,980	$	124.84
Vested	(317,128)	$	105.03	(202,352)	$	116.28
Forfeited	(29,945)	$	131.55	(7,905)	$	161.49
Nonvested at December 31, 2021(1)	870,777	$	131.64	277,300	$	127.54
Expected to vest at December 31, 2021	854,697	$	131.47	271,197	$	127.47

(1)Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100% of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.

In 2021, 2020 and 2019, the total fair value of RSU shares vested during the year was $57 million, $70 million and $36 million, respectively.

Sempra expects $17 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.5 years. The weighted-average per-share fair values for performance-based RSUs granted were $155.62 and $113.54 in 2020 and 2019, respectively. The weighted-average per-share fair values for service-based RSUs granted were $138.91 and $112.50 in 2020 and 2019, respectively.

NOTE 9. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposure is commodity market risk. Our use of derivatives for this risk is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.

In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

In all other cases, we record derivatives at fair value on the Balance Sheet. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges and undesignated derivatives not subject to rate recovery). We classify cash flows from the settlements of our derivative instruments as operating activities on the Statement of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments . Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:

▪We use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed-price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Statement of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

▪We are allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations.

▪From time to time, we may use other energy derivatives to hedge exposures such as GHG allowances.

The following table summarizes net energy derivative volumes.


NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
		December 31,
Commodity	Unit of measure	2021	2020
Natural gas	MMBtu	7	16
Electricity	MWh	1	1
Congestion revenue rights	MWh	45	43

FINANCIAL STATEMENT PRESENTATION

The Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Balance Sheet, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions.


DERIVATIVE INSTRUMENTS ON THE BALANCE SHEET
(Dollars in millions)
	December 31, 2021
	Other current assets		Other long-term assets		Other current liabilities		Deferred credits and other
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	34	$	52	$	(20)	$	—
Associated offsetting commodity contracts	(5)		—		5		—
Net amounts presented on the balance sheet	29		52		(15)		—
Additional cash collateral for commodity contracts subject to rate recovery	28		—		—		—
Total(1)	$	57	$	52	$	(15)	$	—
	December 31, 2020
	Other current assets		Other long-term assets		Other current liabilities		Deferred credits and other
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	32	$	95	$	(28)	$	(25)
Associated offsetting commodity contracts	(1)		—		1		—
Net amounts presented on the balance sheet	31		95		(27)		(25)
Additional cash collateral for commodity contracts subject to rate recovery	24		—		—		—
Total(1)	$	55	$	95	$	(27)	$	(25)

(1)Included in Current Assets: Fixed-Price Contracts and Other Derivatives.

The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Statement of Operations.


UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2021		2020		2019

Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	31	$	88	$	(140)

CONTINGENT FEATURES

Certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization. SDG&E did not have this group of derivative instruments in a liability position at December 31, 2021 or 2020.

Some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above..

NOTE 10. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASURES

The tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2021 and 2020. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair-valued assets and liabilities, and their placement within the fair value hierarchy.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 under “Financial Statement Presentation.”

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following:

▪Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding accounts receivable and accounts payable. A third-party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

▪For commodity contracts, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions, as we discuss below in “Level 3 Information.”

▪Rabbi Trust investments include short-term investments that consist of money market and mutual funds that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).


RECURRING FAIR VALUE MEASURES
(Dollars in millions)
	Fair value at December 31, 2021
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	13	$	(10)	$	—	$	3
Equity securities	358		$	6	$	—	364
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	48		8		—		56
Municipal bonds	—		321		—		321
Other securities	—		260		—		260
Total debt securities	48		589		—		637
Total nuclear decommissioning trusts(1)	419		585		—		1,004
Commodity contracts subject to rate recovery	12		—		69		81
Effect of netting and allocation of collateral(2)	22		—		6		28
Total	$	453	$	585	$	75	1,113
Liabilities:
Commodity contracts subject to rate recovery	$	—	$	—	$	15	$	15
Total	$	—	$	—	$	15	$	15
	Fair value at December 31, 2020
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$	9	$	(6)	$	—	$	3
Equity securities	358		6		—		364
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	41		24		—		269
Municipal bonds	—		326		—		326
Other securities	—		270		—		270
Total debt securities	41		620		—		661
Total nuclear decommissioning trusts(1)	408		620		—		1,028
Commodity contracts subject to rate recovery	5		—		121		126
Effect of netting and allocation of collateral(2)	18		—		6		24
Total	$	431	$	620	$	127	1,178
Liabilities:
Commodity contracts subject to rate recovery	$	—	$	—	$	52	$	52
Total	$	—	$	—	$	52	$	52

(1)Excludes cash balances and cash equivalents.

(2)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

The table below sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for SDG&E.


LEVEL 3 RECONCILIATIONS(1)
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
Balance at January 1	$	69	$	28	$	179
Realized and unrealized gains (losses)	(50)		19		(184)
Allocated transmission instruments	3		6		6
Settlements	32		16		27
Balance at December 31	$	54	$	69	$	28
Change in unrealized gains (losses) relating to instruments still held at December 31	$	(16)	$	34	$	(139)

(1)Excludes the effect of the contractual ability to settle contracts under master netting agreements.

Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:


CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS

Settlement year	Price per MWh				Median price per MWh
2022	$	(3.67)	to	6.96	$	(0.70)
2021	(1.81)		to	14.11	(0.12)
2020	(3.77)		to	6.03	(1.58)

The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 9.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31 were as follows:


LONG-TERM, FIXED-PRICE ELECTRICITY POSITIONS PRICE INPUTS

Settlement year	Price per MWh					Weighted-average price per MWh
2021	$	24.10	to	$	105.00	$	53.57
2020	19.60		to	78.10		39.71

A significant increase (decrease) in market electricity forward prices would result in a significantly higher (lower) fair value. We summarize long-term, fixed-price electricity position volumes in Note 9.

Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, accounts receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Balance Sheet.


FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	Carrying		Fair value
	amount		Level 1		Level 2		Level 3		Total
	December 31, 2021

Total long-term debt(1)	$	6,417	$	—	$	7,236	$	—	$	7,236

	December 31, 2020

Total long-term debt(1)	$	6,053	$	—	$	7,184	$	—	$	7,184

(1)Before reductions of unamortized discount and debt issuance costs of $61 and $52 at December 31, 2021 and 2020, respectively, and excluding finance lease obligations of $1,274 and $1,276 at December 31, 2021 and 2020, respectively.

We provide the fair values for the securities held in the NDT related to SONGS in Note 12.

NOTE 11. PREFERRED STOCK

SDG&E is authorized to issue up to 45 million shares of preferred stock, respectively. At December 31, 2021 and 2020, SDG&E had no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by SDG&E’s board of directors at the time of issuance.

NOTE 12. SAN ONOFRE NUCLEAR GENERATING STATION

SDG&E has a 20% ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage as a result of issues with the steam generators used in the facility. Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in SDG&E’s Statement of Operations.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to take approximately 10 years. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The spent fuel is currently being stored on-site, until the DOE identifies a spent fuel storage facility and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately 20% of the total decommissioning cost.

The Samuel Lawrence Foundation filed a writ petition under the California Coastal Act in LA Superior Court in December 2019 seeking to invalidate the coastal development permit and to obtain injunctive relief to stop decommissioning work. The petition was denied in September 2021. In December 2021, the foundation filed a notice of appeal. In September 2020, the foundation filed another writ petition under the California Coastal Act in LA Superior Court seeking to set aside the CCC’s July 2020 approval of the inspection and maintenance plan for the SONGS’ canisters and to obtain injunctive relief to stop decommissioning work. In December 2021, the foundation filed a request for dismissal. To date, decommissioning work has not been interrupted as a result of these writ petitions.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Balance Sheet at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In December 2021, SDG&E received authorization from the CPUC to access NDT funds of up to $78 million for forecasted 2022 costs.

In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.

The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the

DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.

Nuclear Decommissioning Trusts

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Balance Sheet. We provide additional fair value disclosures for the NDT in Note 10.


NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses		Estimated fair value
At December 31, 2021:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies(1)	$	56	$	—	$	—	$	56
Municipal bonds(2)	309		13		(1)		321
Other securities(3)	255		7		(2)		260
Total debt securities	620		20		(3)		637
Equity securities	104		262		(2)		364
Short-term investments, primarily cash equivalents	3		—		—		3
Receivables (payables), net	8		—		—		8
Total	$	735	$	282	$	(5)	$	1,012
At December 31, 2020:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	$	64	$	1	$	—	$	65
Municipal bonds	308		18		—		326
Other securities	253		17		—		270
Total debt securities	625		36		—		661
Equity securities	112		254		(2)		364
Short-term investments, primarily cash equivalents	3		—		—		3
Receivables (payables), net	(9)		—		—		(9)
Total	$	731	$	290	$	(2)	$	1,019

(1)Maturity dates are 2022-2052.

(2)Maturity dates are 2022-2056.

(3)Maturity dates are 2022-2072.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.


SALES OF SECURITIES IN THE NDT
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
Proceeds from sales	$	961	$	1,439	$	914
Gross realized gains	67		156		24
Gross realized losses	(5)		(17)		(5)

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on SDG&E’s Balance Sheet. We determine the cost of securities in the trusts on the basis of specific identification.

ASSET RETIREMENT OBLIGATION

The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $568 million at December 31, 2021 and is based on a cost study prepared in 2020, which will be submitted to the CPUC in the first half of 2022. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $79 million in 2022, $66 million in 2023, $77 million in 2024, $46 million in 2025, $52 million in 2026, and $718 million thereafter.

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018, which is pending DOE approval. It is unclear when Edison will pursue litigation claims for spent fuel management costs incurred on or after August 1, 2018. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $110 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $450 million insurance limit, this additional coverage would be available to provide a total of $560 million in coverage limits per incident.

The SONGS owners have nuclear property damage insurance of $130 million, which exceeds the minimum federal requirements of $50 million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $4.3 million of retrospective premiums based on overall member claims.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

NOTE 13. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.

At December 31, 2021, loss contingency accruals for legal matters that are probable and estimable were $4 million. We discuss our policy regarding accrual of legal fees in Note 1.

Ordinary Course Litigation

We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

LEASES

A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.

Some of our lease agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. As the lessee for both operating and finance leases, we have elected to combine lease and nonlease components as a single lease component for real estate, fleet vehicles, power generating facilities, and pipelines, whereby fixed or in-substance fixed payments allocable to the nonlease component are accounted for as part of the related lease liability and ROU asset. As the lessor, we have elected to combine lease and nonlease components as a single lease component for real estate and power generating facilities if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.

Lessee Accounting

We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.

Some of our leases include options to extend the lease terms for up to 20 years. Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.

Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.

Certain of our leases contain escalation clauses requiring annual increases in rent ranging from 2% to 3% or based on the Consumer Price Index. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year. Variable lease payments that are based on an index or rate are included in the initial measurement of our lease liability and ROU asset based on the index or rate at lease commencement and are not remeasured because of changes to the index or rate. Rather, changes to the index or rate are treated as variable lease payments and recognized in the period in which the obligation for those payments is incurred.

Similarly, PPAs for the purchase of renewable energy require lease payments based on a stated rate per MWh produced by the facilities, and we are required to purchase substantially all the output from the facilities. SDG&E is required to pay

additional amounts for capacity charges and actual purchases of energy that exceed the minimum energy commitments. Under these contracts, we do not recognize a lease liability or ROU asset for leases for which there are no fixed lease payments. Rather, these variable lease payments are recognized separately as variable lease costs. SDG&E estimates these variable lease payments to be $297 million in 2022, $296 million in 2023, $297 million in 2024, $296 million in 2025, $290 million in 2026 and $2,779 million thereafter.

As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.

For our operating leases, we recognize a single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. We recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

Our leases do not contain any material residual value guarantees, restrictions or covenants.

Classification of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.


LESSEE INFORMATION ON THE BALANCE SHEET
(Dollars in millions)
	December 31,
	2021			2020
Right-of-use assets:
Operating leases:
ROU assets (included in Capital Lease Accounts)	$	185		$	102

Finance leases:
PP&E	1,381			1,356
Accumulated depreciation	(107)			(80)
PP&E, net	1,274			1,276
Total ROU assets	$	1,459		$	1,378

Lease liabilities:
Operating leases:
Other current liabilities(1)	$	26		$	27
Deferred credits and other(2)	159			73
	185			100
Finance leases:
Current portion of long-term debt and finance leases(1)	32			26
Long-term debt and finance leases(2)	1,242			1,250
	1,274			1,276
Total lease liabilities	$	1,459		$	1,376

Weighted-average remaining lease term (in years):
Operating leases	11			6
Finance leases	17			19
Weighted-average discount rate:
Operating leases	3.22		%	3.62		%
Finance leases	14.48		%	14.65		%

(1)Reflected as Obligations under Capital Lease – Current for FERC reporting.

(2)Reflected as Obligations under Capital Lease – Noncurrent for FERC reporting.

The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities:


LESSEE MATURITY ANALYSIS OF LIABILITIES
(Dollars in millions)
	December 31, 2021
	Operating leases(1)		Finance leases(2)
2022	$	30	$	197
2023	27		197
2024	25		192
2025	16		188
2026	15		188
Thereafter	105		2,279
Total undiscounted lease payments	218		3,241
Less: imputed interest	(33)		(1,967)
Total lease liabilities	185		1,274
Less: current lease liabilities	(26)		(32)
Long-term lease liabilities	$	159	$	1,242

(1)Includes $9 in each of 2022 through 2026 and $87 thereafter related to purchased-power contracts.

(2)Substantially all amounts are related to purchased-power contracts.

Leases that Have Not Yet Commenced

SDG&E has entered into three energy storage tolling agreements, of which it expects two will commence in the third quarter of 2022 and one will commence in the second quarter of 2023. SDG&E expects to account for these agreements as operating leases upon commencement and expects the future minimum lease payments to be $8 million in 2022, $17 million in 2023, $18 million in each of 2024 through 2026 and $101 million thereafter until expiration at various dates from 2032 through 2033.

.

CONTRACTUAL COMMITMENTS

Natural Gas Contracts

SoCalGas has responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio from various producing regions in the southwestern U.S., U.S. Rockies and Canada.

SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2032.

Purchased-Power Contracts

For 2022, SDG&E expects to meet its customer power requirements from the following resource types:

▪Long-term contracts: 60% (of which 57% is provided by renewable energy contracts expiring on various dates through 2042)

▪Other SDG&E-owned generation and tolling contracts expiring on various dates through 2039: 46%

▪Spot market sales: (6)%

Payments on our purchased-power contracts could exceed the minimum commitments based on energy needs. At December 31, 2021, the future minimum payments under long-term purchased-power contracts for SDG&E are as follows:


FUTURE MINIMUM PAYMENTS – PURCHASED-POWER CONTRACTS
(Dollars in millions)
2022	$	218
2023	188
2024	162
2025	105
2026	100
Thereafter	817
Total minimum payments(1)	$	1,590

(1)Excludes purchase agreements accounted for as finance leases.

Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $63 million in each of 2022 through 2026 and $430 million thereafter. Total payments under purchased-power contracts for SDG&E were $495 million in 2021, $534 million in 2020 and $744 million in 2019.

Construction and Development Projects

At December 31, 2021, SDG&E has commitments to make future payments of $27 million for construction projects that include:

▪$4 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and

▪$23 million related to spent fuel management at SONGS.

SDG&E expects future payments under these contractual commitments to be $3 million in each of 2022 and 2023, $1 million in each of 2024 through 2026 and $18 million thereafter.

OTHER COMMITMENTS

We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 12.

Fire Mitigation Fund

In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected to be $4 million per year in 2022 through 2026 and $275 million thereafter, subject to escalation of 2% per year, for a remaining 48-year period. At December 31, 2021, the present value of these future payments of $122 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.

Franchise Agreements

In December 2020, the City of San Diego and SDG&E agreed to extend SDG&E’s natural gas and electric franchises for the city to June 1, 2021. After completing a competitive bid process, on June 8, 2021, the City of San Diego approved ordinances granting to SDG&E the natural gas and electric franchises for the city. These franchise agreements provide SDG&E the opportunity to serve the City of San Diego for the next 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal with a supermajority vote. The agreements went into effect in July 2021. Over the 20-year term of the agreements, SDG&E will make principal payments of $110 million and interest payments of $13 million as consideration for the natural gas and electric franchise agreements. The consideration paid will not be recovered from customers and will be amortized over 20 years. SDG&E paid $11 million to the City of San Diego in 2021. At December 31, 2021, SDG&E has commitments to make future payments of $14 million per year in 2022 through 2024, $15 million in 2025, $4 million in 2026 and $51 million thereafter.

Two lawsuits have been filed in the California Superior Court challenging the City’s process for its award of the natural gas and electric franchises and seeking to declare the franchise agreements null and void.

ENVIRONMENTAL ISSUES

Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.

In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Our costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.

We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $1 million or 1% of current assets, which was $14 million at December 31, 2021.

Other Environmental Issues

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:


CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2021		2020		2019
SDG&E	$	32	$	39	$	39

Our costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing us include (1) investigation and remediation of manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by us at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.

The table below shows the status at December 31, 2021 of our manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:


STATUS OF ENVIRONMENTAL SITES

	# Sites complete(1)	# Sites in process

Manufactured-gas sites	3	—
Third-party waste-disposal sites	2	1

(1)There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.

The following table shows our accrued liabilities for environmental matters at December 31, 2021.


ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
	Manufactured- gas sites		Waste disposal sites (PRP)(1)		Other hazardous waste sites		Total(2)
SDG&E(3)	$	—	$	6	$	12	$	18

(1)Sites for which we have been identified as a PRP.

(2)Includes $1 million classified as current liabilities, and $4 million classified as noncurrent liabilities on SDG&E’s Balance Sheet.

(3)Does not include SDG&E’s liability for SONGS marine environment mitigation.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 12, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the estimated mitigation costs is $97 million, of which $53 million has been incurred through December 31, 2021 and $44 million is accrued for remaining costs through 2053, which is recoverable in rates and included in noncurrent Regulatory Assets on the Balance Sheet.

We expect future payments related to our environmental liabilities on an undiscounted basis to be $2 million in each of 2022 through 2025, $14 million in 2026 and $40 million thereafter.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 2021 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.


GLOSSARY
2019 GRC FD			final decision in SDG&E’s 2019 General Rate Case
AB			California Assembly Bill
AFUDC			allowance for funds used during construction
AMP			Arrearage Management Payment Plan
AOCI			accumulated other comprehensive income (loss)
ARO			asset retirement obligation
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
bps			basis points
CARB			California Air Resources Board
CCC			California Coastal Commission
CCM			cost of capital adjustment mechanism
COVID-19			coronavirus disease 2019
CPUC			California Public Utilities Commission
CRR			congestion revenue right
DOE			U.S. Department of Energy
DWR			California Department of Water Resources
Edison			Southern California Edison Company, a subsidiary of Edison International
Enova			Enova Corporation
EPS			earnings (losses) per common share
ESJ			Energía Sierra Juárez, S. de R.L. de C.V.
ETR			effective income tax rate
FERC			Federal Energy Regulatory Commission
GHG			greenhouse gas
GRC			General Rate Case
IOU			investor-owned utility
IRS			U.S. Internal Revenue Service
ISFSI			independent spent fuel storage installation
ISO			Independent System Operator
LA Superior Court			Los Angeles County Superior Court
MMBtu			million British thermal units (of natural gas)
Moody’s			Moody’s Investors Service
MW			megawatt
MWh			megawatt hour
NAV			net asset value
NDT			nuclear decommissioning trusts
NEIL			Nuclear Electric Insurance Limited
NRC			Nuclear Regulatory Commission
O&M			operation and maintenance expense
OCI			other comprehensive income (loss)
OEIS			Office of Energy Infrastructure Safety
OIR			Order Instituting a Rulemaking
OMEC			Otay Mesa Energy Center
PBOP			postretirement benefits other than pension
PG&E			Pacific Gas and Electric Company
PP&E			property, plant and equipment
PPA			power purchase agreement
PRP			Potentially Responsible Party
REC			renewable energy certificate
ROE			return on equity
ROU			right-of-use


GLOSSARY
RPS			Renewables Portfolio Standard
RSU			restricted stock unit
S&P			S&P Global Ratings, a division of S&P Global Inc.
SDG&E			San Diego Gas & Electric Company
SEC			U.S. Securities and Exchange Commission
Sempra			Sempra Energy doing business as Sempra, together with its consolidated entities unless otherwise stated or indicated by the context
SoCalGas			Southern California Gas Company
SONGS			San Onofre Nuclear Generating Station
TCJA			Tax Cuts and Jobs Act of 2017
TO4			Electric Transmission Owner Formula Rate, effective through May 31, 2019
TO5			Electric Transmission Owner Formula Rate, effective June 1, 2019
U.S. GAAP			generally accepted accounting principles in the United States of America
Wildfire Fund			the fund established pursuant to AB 1054
Wildfire Legislation			AB 1054 and AB 111

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year		15,874,048					15,874,048
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3	Preceding Quarter/Year to Date Changes in Fair Value		5,839,946					5,839,946
4	Total (lines 2 and 3)		5,839,946					5,839,946	824,492,862	830,332,808
5	Balance of Account 219 at End of Preceding Quarter/Year		10,034,102					10,034,102
6	Balance of Account 219 at Beginning of Current Year		10,034,102					10,034,102
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8	Current Quarter/Year to Date Changes in Fair Value		82,938					82,938
9	Total (lines 7 and 8)		82,938					82,938	(a) 819,252,902	819,169,964
10	Balance of Account 219 at End of Current Quarter/Year		10,117,040					10,117,040

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: NetIncomeLoss

South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	23,327,823,836	18,107,371,442	3,200,655,070				2,019,797,324
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	1,649,438,076	1,412,542,088					236,895,988
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold	0
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	0
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified	0
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	24,977,261,912	19,519,913,530	3,200,655,070				2,256,693,312
9	UtilityPlantLeasedToOthers Leased to Others	112,194,000	112,194,000
10	UtilityPlantHeldForFutureUse Held for Future Use	0
11	ConstructionWorkInProgress Construction Work in Progress	1,670,246,956	1,110,158,230	202,750,290				357,338,436
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	3,750,722	3,750,722
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	26,763,453,590	20,746,016,482	3,403,405,360				2,614,031,748
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	(a) 8,253,275,451	6,345,189,796	946,127,200				961,958,455
15	UtilityPlantNet Net Utility Plant (13 less 14)	18,510,178,139	14,400,826,686	2,457,278,160				1,652,073,293
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	7,314,136,707	5,966,016,105	936,724,642				411,395,960
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights	0
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights	0
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	905,166,125	345,201,072	9,402,558				550,562,495
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	8,219,302,832	6,311,217,177	946,127,200				961,958,455
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation	31,472,139	31,472,139
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion	0
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)	31,472,139	31,472,139
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation	0
29	AmortizationUtilityPlantHeldForFutureUse Amortization	0
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	0
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)	0
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	2,500,480	2,500,480
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	(b) 8,253,275,451	6,345,189,796	946,127,200				961,958,455

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility

Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking

Accumulated Provision for Depreciation & Amortization Classified

under FERC Seven Factor Test

In Accordance with Guidelines in FERC Order 888


			Accumulated Provision
Electric
Intangible Plant			173,963,956
Steam Production Plant			305,885,272
Other Production Plant			272,588,028
Transmission Plant			1,635,135,373
Distribution Plant			3,606,168,212
General Plant			219,537,534

Ratemaking Electric			6,213,278,375

Nuclear Decommissioning			1,011,036,365
ASC 410 (FAS 143 and FIN 47) - Electric			(1,018,731,937)
Capital Leases A/D			90,279,107
Leased to Others- Citizens A/D (Sunrise)			29,238,086
Leased to Others- Citizens A/D (SX-PQ)			2,234,053
Cuyamaca Permanent Adjustment			17,855,747

Total Electric			6,345,189,796

Ratemaking Gas			1,161,217,848
FIN 47 - Gas			(215,090,648)

Total Gas			946,127,200

Ratemaking Common			857,931,943
FIN 47 - Common			2,922,489
Capital Lease A/D			101,104,023

Total Common			961,958,455

Total Accumulated Provision EOQ 12/2021			8,253,275,451

Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production			293,178,925

Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production			284,106,681

Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant			1,544,320,791

(b) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility

Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking

Accumulated Provision for Depreciation & Amortization Classified

under FERC Seven Factor Test

In Accordance with Guidelines in FERC Order 888


			Accumulated Provision
Electric
Intangible Plant			173,963,956
Steam Production Plant			305,885,272
Other Production Plant			272,588,028
Transmission Plant			1,635,135,373
Distribution Plant			3,606,168,212
General Plant			219,537,534

Ratemaking Electric			6,213,278,375

Nuclear Decommissioning			1,011,036,365
ASC 410 (FAS 143 and FIN 47) - Electric			(1,018,731,937)
Capital Leases A/D			90,279,107
Leased to Others- Citizens A/D (Sunrise)			29,238,086
Leased to Others- Citizens A/D (SX-PQ)			2,234,053
Cuyamaca Permanent Adjustment			17,855,747

Total Electric			6,345,189,796

Ratemaking Gas			1,161,217,848
FIN 47 - Gas			(215,090,648)

Total Gas			946,127,200

Ratemaking Common			857,931,943
FIN 47 - Common			2,922,489
Capital Lease A/D			101,104,023

Total Common			961,958,455

Total Accumulated Provision EOQ 12/2021			8,253,275,451

Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production			293,178,925

Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production			284,106,681

Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant			1,544,320,791

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
1	Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2	Fabrication
3	Nuclear Materials
4	Allowance for Funds Used during Construction
5	(Other Overhead Construction Costs, provide details in footnote)
6	SUBTOTAL (Total 2 thru 5)
7	Nuclear Fuel Materials and Assemblies
8	In Stock (120.2)
9	In Reactor (120.3)
10	SUBTOTAL (Total 8 & 9)
11	Spent Nuclear Fuel (120.4)
12	Nuclear Fuel Under Capital Leases (120.6)
13	(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14	TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15	Estimated Net Salvage Value of Nuclear Materials in Line 9
16	Estimated Net Salvage Value of Nuclear Materials in Line 11
17	Est Net Salvage Value of Nuclear Materials in Chemical Processing
18	Nuclear Materials held for Sale (157)
19	Uranium
20	Plutonium
21	Other (Provide details in footnote)
22	TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization
3	(302) Franchise and Consents	222,841					222,841
4	(303) Miscellaneous Intangible Plant	191,341,267	569,423		17,094		191,893,596
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	191,564,108	569,423		17,094		192,116,437
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	14,526,518					14,526,518
9	(311) Structures and Improvements	91,410,208	21,264		1,318		91,430,154
10	(312) Boiler Plant Equipment	162,192,323	2,865,019		672		165,056,670
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	131,402,613	1,338,434		1,500		132,739,547
13	(315) Accessory Electric Equipment	86,962,688			797		86,961,891
14	(316) Misc. Power Plant Equipment	59,602,710	5,286,153		2,685		64,886,178
15	(317) Asset Retirement Costs for Steam Production	5,259,070			3,303,758		1,955,312
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	551,356,130	9,510,870		3,310,730		557,556,270
17	B. Nuclear Production Plant
18	(320) Land and Land Rights
19	(321) Structures and Improvements
20	(322) Reactor Plant Equipment
21	(323) Turbogenerator Units
22	(324) Accessory Electric Equipment
23	(325) Misc. Power Plant Equipment
24	(326) Asset Retirement Costs for Nuclear Production
25	TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26	C. Hydraulic Production Plant
27	(330) Land and Land Rights
28	(331) Structures and Improvements
29	(332) Reservoirs, Dams, and Waterways
30	(333) Water Wheels, Turbines, and Generators
31	(334) Accessory Electric Equipment
32	(335) Misc. Power Plant Equipment
33	(336) Roads, Railroads, and Bridges
34	(337) Asset Retirement Costs for Hydraulic Production
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36	D. Other Production Plant
37	(340) Land and Land Rights	226,796					226,796
38	(341) Structures and Improvements	24,812,767	127,058		359	1,000	24,940,466
39	(342) Fuel Holders, Products, and Accessories	22,279,073			80		22,278,993
40	(343) Prime Movers	105,365,778	166,380		691		105,531,467
41	(344) Generators	366,763,275	9,126,937	38,248,482	80,809	1,000	337,559,921
42	(345) Accessory Electric Equipment	33,767,456	129,106		10		33,896,552
43	(346) Misc. Power Plant Equipment	40,164,692	29,128,792		2,683		69,290,801
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	593,379,837	38,678,273	38,248,482	84,632		593,724,996
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	1,144,735,967	48,189,143	38,248,482	3,395,362		1,151,281,266
47	3. Transmission Plant
48	(350) Land and Land Rights	252,442,567	4,009,991		1,551		256,451,007
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	669,356,121	82,918,323	195,778	193,935	35,702	751,849,029
50	(353) Station Equipment	1,966,465,850	209,901,233	1,667,653	576,604	1,396,399	2,172,726,427
51	(354) Towers and Fixtures	922,725,564	6,653,764		3,955		929,375,373
52	(355) Poles and Fixtures	930,750,214	59,371,599	7,684,894	387,241	11	982,049,689
53	(356) Overhead Conductors and Devices	821,798,414	47,516,727	1,919,462	105,037	140,894	867,149,748
54	(357) Underground Conduit	550,520,796	10,355,756		388,314		560,488,238
55	(358) Underground Conductors and Devices	557,705,658	12,712,430		345,656		570,072,432
56	(359) Roads and Trails	370,697,495	9,872,611		411,184		380,158,922
57	(359.1) Asset Retirement Costs for Transmission Plant	928,663			4,639,851		5,568,514
58	TOTAL Transmission Plant (Enter Total of lines 48 thru 57)	7,043,391,342	443,312,434	11,467,787	2,226,374	1,572,984	7,475,889,379
59	4. Distribution Plant
60	(360) Land and Land Rights	110,481,006	4,210,681	5,191	1,396		114,687,892
61	(361) Structures and Improvements	12,303,450	962,349	904	240		13,264,655
62	(362) Station Equipment	617,985,881	44,983,038	1,217,011	44,381	321,782	661,385,745
63	(363) Energy Storage Equipment – Distribution	125,965,956	56,804,921		21,285		182,749,592
64	(364) Poles, Towers, and Fixtures	941,396,761	115,627,829	23,148,506	82,165	130,864	1,033,663,055
65	(365) Overhead Conductors and Devices	974,345,978	193,551,872	7,876,954	82,168	556,168	1,159,382,560
66	(366) Underground Conduit	1,598,054,522	124,992,054	1,899,720	36,743	23,868,557	1,697,241,556
67	(367) Underground Conductors and Devices	1,763,177,307	213,864,845	11,707,090	2,511,620	26,741,936	1,994,588,618
68	(368) Line Transformers	752,621,931	46,277,655	3,259,202	29,321		795,611,063
69	(369) Services	620,724,886	88,937,539	1,658,225	41,923	1,859,305	706,102,972
70	(370) Meters	273,059,948	14,687,470	755,553	140		286,991,725
71	(371) Installations on Customer Premises	74,443,380	537,620	15,382	6,938	6,207	74,952,473
72	(372) Leased Property on Customer Premises
73	(373) Street Lighting and Signal Systems	34,064,775	1,796,850	65,672	3,126	326	35,792,501
74	(374) Asset Retirement Costs for Distribution Plant	25,092,921			12,325,699		12,767,222
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	7,923,718,702	907,234,723	51,609,410	10,161,113	1,273	8,769,181,629
76	5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77	(380) Land and Land Rights
78	(381) Structures and Improvements
79	(382) Computer Hardware
80	(383) Computer Software
81	(384) Communication Equipment
82	(385) Miscellaneous Regional Transmission and Market Operation Plant
83	(386) Asset Retirement Costs for Regional Transmission and Market Oper
84	TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85	6. General Plant
86	(389) Land and Land Rights	7,312,143					7,312,143
87	(390) Structures and Improvements	45,611,646			24,478	118,133	45,469,035
88	(391) Office Furniture and Equipment
89	(392) Transportation Equipment	58,146					58,146
90	(393) Stores Equipment	46,522			490		46,032
91	(394) Tools, Shop and Garage Equipment	37,634,714	3,490,439	228,053	115		40,896,985
92	(395) Laboratory Equipment	5,336,019					5,336,019
93	(396) Power Operated Equipment	60,529					60,529
94	(397) Communication Equipment	387,968,334	27,475,567	287,150	302,598	1,570,604	416,424,757
95	(398) Miscellaneous Equipment	3,204,867	114,293	12,045	11,689	3,654	3,299,080
96	SUBTOTAL (Enter Total of lines 86 thru 95)	487,232,920	31,080,299	527,248	339,370	1,456,125	518,902,726
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	487,232,920	31,080,299	527,248	339,370	1,456,125	518,902,726
100	TOTAL (Accounts 101 and 106)	16,790,643,039	1,430,386,022	101,852,927	11,686,565	118,132	18,107,371,437
101	(102) Electric Plant Purchased (See Instr. 8)
102	(Less) (102) Electric Plant Sold (See Instr. 8)
103	(103) Experimental Plant Unclassified
104	TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)	16,790,643,039	1,430,386,022	101,852,927	11,686,565	118,132	(a) 18,107,371,437

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: ElectricPlantInService

Reclassification of 2021 Electric Plant-in-Service for Ratemaking

Plant in Service Classified under FERC Seven Factor Test

In Accordance with Guidelines in FERC Order 888


	BOY 2021	EOY 2021

Intangible Plant	191,341,265	191,893,594
Steam Production Plant	561,761,598	571,265,496
Nuclear Production Plant	—	—	*
Other Production Plant	537,020,375	537,622,612
Transmission Plant	6,921,237,975	7,334,224,128
Distribution Plant	8,046,663,231	8,919,066,814
General Plant	487,232,916	518,902,724
Ratemaking Electric	16,745,257,360	18,072,975,368

ASC 410 (FAS 143 and FIN 47)	31,280,654	20,291,049
Cuyamaca Permanent Adjustment	14,105,025	14,105,025

Total Electric Plant-in-Service	16,790,643,039	18,107,371,442


Total 13-Month Average Plant Balance for 2021 - Steam Production		566,175,050

Total 13-Month Average Plant Balance for 2021 - Other Production		542,749,890

Total 13-Month Average Plant Balance for 2021 - Transmission Plant		7,094,919,316


* As a result of the SONGS plant closure, the December 2021 Nuclear Production Plant Balance is zero.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
1	Citizens Sunrise Transmission LLC	True	30 Mile-500KV Transmission Line	10/19/2012	07/02/2042	85,194,000
2			(Border-East Line)
3	Citizens Sycamore-Penasquitos	True	11.5 Mile-Underground 230KV	08/21/2019	06/01/2049	27,000,000
4	Transmission LLC		Transmission Line (Segment B)
47	TOTAL					112,194,000

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21	Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	PALOMAR ENERGY CENTER OPERATIONAL ENHANCEMENTS	3,272,495
2	TL628 CABLE REPLACEMENT	1,210,047
3	TL6916 POLE REPLACEMENT	3,708,450
4	SAN MARCOS SUB REBUILD 69KV & 12 KV	1,306,900
5	TL13831 WOOD TO STEEL REPLACEMENT	4,284,564
6	TL694 WOOD TO STEEL REPLACEMENT	2,671,701
7	GENERATION HYDROGEN PROJECT	1,279,874
8	TL636 WOOD POLE REPLACEMENT	5,683,147
9	TL600 RELIABILITY POLE REPLACEMENTS	6,801,817
10	TL667 CABLE REPLACEMENT	1,822,930
11	GRANITE SUBSTATION 69KV LOOP-IN	3,384,388
12	POWAY SUBSTATION REBUILD	10,910,035
13	TL603B SWEETWATER TAP REMOVAL	7,939,057
14	TRANSMISSION FIBER OPTIC NETWORK	31,210,278
15	FALLBROOK BATTERY ENERGY STORAGE SYSTEM	1,715,588
16	OVERSTRESSED BREAKER REPLACEMENTS	8,754,968
17	TRANSMISSION TRAINING YARD EXPANSION	1,387,689
18	TL686 WARNERS-NARROWS POLE REPLACEMENT	7,159,332
19	TL674A RECONFIGURE	12,587,162
20	TL664 SOUTHBAY-SWEETWATER UPGRADE	7,497,306
21	TL691 WOOD TO STEEL REPLACEMENT	10,340,670
22	TL6975 ESCONDIDO - SAN MARCOS	15,658,569
23	TRANSMISSION SYSTEM AUTOMATION	13,836,438
24	MIGUEL SUB 230KV REBUILD	10,689,639
25	TL690 WOOD TO STEEL REPLACEMENT	8,880,052
26	TL673 CABLE REPLACE	23,321,168
27	TL695 SW POLE REPLACEMENT	11,488,982
28	TL13838 WOOD TO STEEL REPLACEMENT	2,106,297
29	TL615/659 CABLE REPLACEMENT	21,906,966
30	SUBSTATION RELIABILITY UPGRADE PROJECT	3,115,692
31	TL6926 RINCON-VALLEY CENTER POLE REPLACEMENT	87,463,002
32	CONDITION BASED MONITORING - CIRCUIT BREAKERS	9,405,700
33	TL605 RECONDUCTOR	6,100,858
34	SYNCHRONIZED PHASOR MEASUREMENT SYSTEM	1,888,922
35	MISSION 230KV REBUILD	9,028,537
36	SUBSTATION SECURITY PROJECTS	8,238,324
37	CRITICAL ASSET SECURITY	20,851,410
38	TRANSMISSION INFRASTRUCTURE IMPROVEMENTS	13,577,946
39	FIBER OPTIC FOR RELAY PROTECTION & TELECOMMUNICATION	25,821,878
40	TRANSMISSION COMPLIANCE PROGRAM	25,549,760
41	FIRE THREAT ZONE COMPLIANCE PROGRAM	4,799,309
42	MOBILE HOME PARK UTILITY UPGRADES	1,494,812
43	TL679 CUSTOMER RELOCATION	2,126,286
44	GRANITE SUBSTATION 12KV BREAKER REPLACEMENT	3,033,453
45	DRONE INVESTIGATION ASSESSMENT & REPAIR	3,124,745
46	TL23001 INSULATOR REPLACEMENT	3,613,197
47	HEAVY DUTY VEHICLE CHARGING INFRASTRUCTURE	3,219,264
48	TL13811 WOOD TO STEEL REPLACEMENT	1,001,173
49	POWER QUALITY PROGRAM	3,357,199
50	FALLBROOK BATTERY ENERGY STORAGE SYSTEM_1	6,487,782
51	TL639 POLE REPLACEMENT	2,325,359
52	URBAN SUBSTATION SWITCHGEAR REPLACEMENT	2,674,074
53	IV SUBSTATION SHUNT REPLACEMENT	1,487,203
54	DESERT STAR ENERGY CENTER	1,199,151
55	HFTD OVERHEAD EQUIPMENT REPLACEMENT	3,114,301
56	ARTESIAN 230KV SUBSTATION EXPANSION	54,996,438
57	NON-HFTD OVERHEAD EQUIPMENT REPLACEMENT	4,218,061
58	ORANGE COUNTY LONG RANGE PLAN	71,711,370
59	SUNCREST TERTIARY REACTOR REPLACEMENT	1,908,801
60	TEE MODERNIZATION PROGRAM	1,032,414
61	4KV MODERNIZATION	4,100,386
62	HFTD FUSE REPLACEMENTS	1,930,736
63	DOE SWITCH REPLACEMENT	5,533,813
64	DISTRIBUTION SYSTEM CAPACITY IMPROVEMENT	1,792,760
65	REACTIVE SMALL CAPITAL PROJECTS	1,753,211
66	UG DISTRIBUTION SERVICE MANAGEMENT	1,793,497
67	DISTRIBUTION SUBSTATION RELIABILITY	3,393,378
68	PSPS ENGINEERING ENHANCEMENTS	4,326,242
69	SAN MATEO SUB REBUILD	3,402,002
70	CORRECTIVE MAINTENANCE PROGRAM	3,187,961
71	NEW BUSINESS INFRASTRUCTURE	5,123,020
72	OBSOLETE SUBSTATION EQUIPMENT REPLACEMENT	1,752,552
73	CORRECTIVE MAINT. PROG. (CMP) UG SWITCH REPLAC. & MANHOLE REPAIR	1,203,928
74	UG NON-RESIDENTIAL NEW BUSINESS	7,161,423
75	NEW SERVICE INSTALLATIONS	4,490,973
76	OH DISTRIBUTION SERVICE MANAGEMENT	6,705,462
77	SUBSTATION BREAKER AND RELAY REPLACEMENTS	7,542,478
78	MID-COAST TROLLEY EXTENSION PROJECT	1,180,036
79	STREAMVIEW SUBSTATION 69/12KV REBUILD	4,744,958
80	UG RESIDENTIAL NEW BUSINESS	7,034,660
81	ELECTRIC DISTRIBUTION STREET & HIGHWAY RELOCATIONS	11,339,323
82	WOOD POLE REINFORCEMENT	6,960,118
83	C1047: NEW 12KV CIRCUIT	2,013,502
84	HFTD TIER 2 & 3 CMP POLE REPLACEMENTS	2,609,405
85	FIRE THREAT ZONE PROTECTION & SCADA UPGRADE	39,140,669
86	PURE WATER PROJECT	2,983,552
87	DISTRIBUTION SUBSTATION SCADA EXPANSION	1,480,466
88	CONVERSION FROM OH TO UG RULE 20A	12,921,381
89	BORREGO MICROGRID	4,854,679
90	GAS INSULATED SWITCH REPLACEMENT	1,934,999
91	C724: NEW 12KV CIRCUIT	10,518,704
92	OH PUBLIC SAFETY PROGRAM	12,629,174
93	DISTRIBUTION CIRCUIT RELIABILITY CONSTRUCTION	2,723,187
94	BACKUP POWER FOR RESILIENCY	10,098,642
95	TORREY PINES SUBSTATION 12KV BREAKER REPLACEMENT	2,561,964
96	EL CAJON SUBSTATION 12KV BREAKER REPLACEMENT	1,258,419
97	FIRE THREAT ZONE UNDERGROUNDING	46,855,890
98	C303 RECONDUCTOR	2,731,485
99	EV CHARGING STATIONS AT SCHOOLS	1,380,973
100	EV CHARGING STATIONS AT PUBLIC PARKS	3,609,270
101	KETTNER SUBSTATION REBUILD	2,877,864
102	MOBILE HOME PARK UTILITY CONVERSIONS	5,771,946
103	MISSION SUBSTATION 12KV BREAKER REPLACEMENT	1,578,394
104	ADVANCED ENERGY STORAGE UPGRADES	7,960,106
105	HFTD OVERHEAD DISTRIBTUION HARDENING	111,593,046
106	OH SYSTEM COVERED CONDUCTOR	30,911,041
107	KEARNY BATTERY ENERGY STORAGE PROJECT	23,957,110
108	RAMONA MICROGRID	4,709,321
109	BUTTERFIELD MICROGRID	1,423,076
110	C235 RECONDUCTOR	1,550,343
111	HELICOPTER INFRARED CAMERA	1,045,405
112	SDG&E SOLAR ENERGY PROGRAM	1,812,653
113	DATA FOUNDATION AND REPORTING	6,885,893
114	WILDFIRE SAFETY DIVISION SCHEMA PROJECT	7,100,242
115	WILDFIRE MGMT ASSESSMENT PLATFORM	7,102,751
116	DISTRIBUTION DEFERRAL OPPORTUNITY REPORTING	2,380,427
117	PERCENTAGE OF INCOME PAYMENT PLAN PROGRAM	2,089,314
118	UNALLOCATED CONSTRUCTION OVERHEADS & LABOR ACCRUAL	24,354,479
119	MINOR PROJECTS (LESS THAN $1,000,000)	30,188,673
43	Total	1,110,158,230

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	5,576,471,800	5,549,614,769		26,857,031
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	603,127,309	(a) 603,127,309
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others	4,615,108			4,615,108
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	607,742,417	603,127,309		4,615,108
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	101,847,734	(b) 101,847,734
13	CostOfRemovalOfPlant Cost of Removal	86,663,119	86,663,119
14	SalvageValueOfRetiredPlant Salvage (Credit)	1,955,010	1,955,010
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	186,555,843	186,555,843
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):	6,646,297	(c) 6,646,297
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired	6,476,167	6,476,167
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	5,997,488,244	5,966,016,105		31,472,139
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	300,114,066	300,114,066
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage
24	AccumulatedDepreciationOtherProduction Other Production	302,324,304	302,324,304
25	AccumulatedDepreciationTransmission Transmission	1,659,773,187	1,628,301,048		31,472,139
26	AccumulatedDepreciationDistribution Distribution	3,515,739,153	3,515,739,153
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	219,537,534	219,537,534
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	5,997,488,244	5,966,016,105		31,472,139

FOOTNOTE DATA

(a) Concept: DepreciationExpenseExcludingAdjustments


Depreciation Provision - Electric Only (Line 10, Pg 219)	$	603,127,309
Depreciation Provision - Common Alloc. to Elec. (Line 11, Pg 336)	56,368,616
Depreciation Provision - (Line 6, Col. G, Pg 115)	$	659,495,925

(b) Concept: BookCostOfRetiredPlant


Book Cost of Plant Retired (Line 12, Col. B, Pg 219)	$	(101,847,734)
Total Plant Retired (Line 100, Col. D, Pg 207)	101,852,927
Adj. For Land & Intangible Retirements not impacting	(5,193)
Difference	$	—

(c) Concept: OtherAdjustmentsToAccumulatedDepreciation


SONGS Decommissioning - Current Year Trust Income (Loss)	$	(6,615,047)
Transfer of Reserve Balances between Departments	(31,251)
Other Debit and Credit Items (Line 16, Pg 219)	$	(6,646,298)

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42	Total Cost of Account 123.1 $		Total

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

MATERIALS AND SUPPLIES
For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)
2	Fuel Stock Expenses Undistributed (Account 152)
3	Residuals and Extracted Products (Account 153)
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	131,950,322	123,566,571	ELECTRIC/GAS
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)
8	Transmission Plant (Estimated)
9	Distribution Plant (Estimated)
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	9,947,003	9,314,998	ELECTRIC/GAS
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	141,897,325	132,881,569
13	Merchandise (Account 155)
14	Other Materials and Supplies (Account 156)			COMMON
15	Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16	Stores Expense Undistributed (Account 163)			COMMON
17
18
19
20	TOTAL Materials and Supplies	141,897,325	132,881,569

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	144,627										144,627
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	12,947		12,947		12,947		12,947		349,569		401,357
5	Returned by EPA
6
7
8	Purchases/Transfers:
9	Transfers to Palomar	4										4
10	Transfers to Miramar
11	Transfers to Cuyamaca Peak
12	Transfers to Desert Star	1										1
13
14
15	Total	5										5
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year	157,569		12,947		12,947		12,947		349,569		545,979
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)
5	Returned by EPA
6
7
8	Purchases/Transfers:
9
10
11
12
13
14
15	Total
16
17	Relinquished During Year:
18	Charges to Account 509
19	Other:
20	Allowances Used
21	Cost of Sales/Transfers:
22
23
24
25
26
27
28	Total
29	Balance-End of Year
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20	Total
21	Generation Studies
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39	Total
40	Grand Total

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Deferred Taxes Recoverable in Rates	933,140,071	202,534,339	Various	133,396,552	1,002,277,858
2	Amortized Over Various Lives
3	Employer's Accounting for Post-	6,612,000		Various	1,948,000	4,664,000
4	Employment Benefits
5	Environmental Clean-Up	18,970,953	462,056	Various	1,663,584	17,769,425
6	Balancing Account Undercollections	1,066,520,210	235,633,543	Various	12,015,191	1,290,138,562
7	Pension Benefits	68,654,459		Various	68,570,865	83,594
8	SONGS Mitigation	36,931,880	7,288,911			44,220,791
9	Electric Derivatives	75,094,995		Various	42,489,207	32,605,788
10	Contribution to City of Escondido	902,975		253	162,180	740,795
11	(20 year life, starting 2006)
12	Asset Retirement Obligations	23,319,537	5,822,739	Various	2,882,097	26,260,179
13	Sunrise Wildfire Mitigation	121,485,983	770,193			122,256,176
14	Beyond The Meter	32,769,065	6,615,776	232	4,676,982	34,707,859
15	Theoretical Withdrawal Premium OIL	12,393,779		253	172,801	12,220,978
16	Post Retirement Benefits Other than	1,473,050	769,501			2,242,551
17	Pension
18	Worker's Compensation (Incurred	226,269				226,269
19	But Not Recorded)
20	2000 Energy Crisis Disbursement		1,866,070			1,866,070
44	TOTAL	2,398,495,226	461,763,128		267,977,459	2,592,280,895

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Debt Issuance costs	1,724,882		various	434,793	1,290,089
2	Southwest Powerlink Deferred	285,034		406	15,744	269,290
3	per CPUC
4	(amortization 01/1986 - 12/2023)
5	Mitigation Fund	137,706		various	9	137,697
6	Environmental Program	8,312,535	848,400	various	1,140,576	8,020,359
7	Workers Comp Receivable	11,459,213		various	1,894,099	9,565,114
8	SONGS Decommissioning	132,173	60,477			192,650
9	Pendleton Energy Park	195,734				195,734
10	Franchise Agreement		1,274,025			1,274,025
11	SONGS Reg Asset Receivable	11,586,157		143	11,586,157
12	PBOP Asset	20,085,874		254	10,616,874	9,469,000
13	Surplus Material	5,937,802	585,809			6,523,611
14	Airbus Helicopter Trade Account	462,000				462,000
15	Wildfire Fund AB1054	362,940,501		various	31,479,968	331,460,533
16	(amortization 07/2019-07/2034)
17	Line of credit (LOC) fees	2,491,173		930	747,352	1,743,821
18	Camp Pendleton Easement	517,000				517,000
19	Miscellaneous Other	88,321	5,031	131	35,416	57,936
20	Renewable Meter Adapter		106,206			106,206
47	Miscellaneous Work in Progress
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	426,356,105				371,285,065

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Federal	(a) 66,270,343	(b) 74,502,660
3	State	33,293,445	39,622,432
7	Other
8	TOTAL Electric (Enter Total of lines 2 thru 7)	(c) 99,563,788	(d) 114,125,092
9	Gas
10	Federal	5,393,701	4,120,596
11	State	3,058,219	2,528,489
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)	8,451,920	6,649,085
17.1	Other (Specify)	410,776	410,795
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	108,426,484	121,184,972

Notes

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

Account 190 electric balance at the beginning of the year reflects amortization of transmission related excess deferred federal income taxes in the amount of $1,981,586.

(b) Concept: AccumulatedDeferredIncomeTaxes

Account 190 electric balance at the end of the year reflects amortization of transmission related excess deferred federal income taxes in the amount of $1,839,074.

The deferred tax asset related to FERC transmission on a stand-alone basis as of December 31, 2021, 2020, 2019, 2018 and 2017 is reflected in the table below:

STAND-ALONE FERC TRANSMISSION NET OPERATING LOSS DEFERRED TAX ASSET (1)

(Dollars in millions)


	Years Ended December 31,
	2021		2020		2019		2018		2017
FERC AC 190
FERC – Remeasured Amount	$	38	$	57	$	119	$	124	$	162
FERC – Excess Reserve Protected	105		107		108		109		$	108
FERC – Excess Reserve Unprotected	—		—		—		—		$	—
Total	$	143	$	164	$	227	$	233	$	270

(1) Does not include any amounts related to Citizens.

(c) Concept: AccumulatedDeferredIncomeTaxes

Account 190 non-Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($164,013,239).

Account 190 Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($8,452,524).

Account 190 transmission allocation related other deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($2,255,357).

(d) Concept: AccumulatedDeferredIncomeTaxes

Account 190 non-Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($143,286,173).

Account 190 Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($7,384,342).

Account 190 transmission allocation related other deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($1,937,052).

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2	Common	255,000,000	2.50		116,583,358	291,458,395
7	Total	255,000,000			116,583,358	291,458,395
8	Preferred Stock (Account 204)
9	Preferred Stock	45,000,000
11	Total	45,000,000
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-04-15

Year/Period of Report

End of:

2021

/

Q4

Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	802,165,368
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	802,165,368
17	OtherPaidInCapitalAbstract Historical Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	802,165,368

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1	Common	24,605,640
22	TOTAL	24,605,640

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	5.350% Series BBB due 2035		250,000,000		2,709,950		295,000	05/19/2005	05/15/2035	05/19/2005	05/15/2035	250,000,000	13,375,000
3	6.000% Series DDD due 2026		250,000,000		2,429,000		1,117,500	06/08/2006	06/01/2026	06/08/2006	06/01/2026	250,000,000	15,000,000
4	6.125% Series FFF due 2037		250,000,000		2,556,327		780,000	09/20/2007	09/15/2037	09/20/2007	09/15/2037	250,000,000	15,312,500
5	6.000% Series GGG due 2039		300,000,000		3,057,571		1,380,000	05/14/2009	06/01/2039	05/14/2009	06/01/2039	300,000,000	18,000,000
6	5.350% Series HHH due 2040		250,000,000		2,486,955		335,000	05/13/2010	05/15/2040	05/13/2010	05/15/2040	250,000,000	13,375,000
7	4.500% Series III due 2040		500,000,000		5,044,008		5,515,000	08/26/2010	08/15/2040	08/26/2010	08/15/2040	500,000,000	22,500,000
8	3.000% Series JJJ due 2021		350,000,000		2,775,568		1,795,500	08/18/2011	08/15/2021	08/18/2011	08/15/2021		6,475,000
9	3.950% Series LLL due 2041		250,000,000		2,639,787		350,000	11/17/2011	11/15/2041	11/17/2011	11/15/2041	250,000,000	9,875,000
10	4.300% Series MMM due 2042		250,000,000		2,569,738		1,297,500	03/22/2012	04/01/2042	03/22/2012	04/01/2042	250,000,000	10,750,000
11	3.600% Series NNN due 2023		450,000,000		3,670,004		72,000	09/09/2013	09/01/2023	09/09/2013	09/01/2023	450,000,000	16,200,000
12	1.914% Series PPP due 2022		250,000,000		1,568,025			03/12/2015	02/01/2022	03/12/2015	02/01/2022	17,859,000	569,677
13	2.500% Series QQQ due 2026		500,000,000		4,279,086		1,625,000	05/19/2016	05/15/2026	05/19/2016	05/15/2026	500,000,000	12,500,000
14	3.750% Series RRR due 2047		400,000,000		4,038,478		1,784,000	06/08/2017	06/01/2047	06/08/2017	06/01/2047	400,000,000	15,000,000
15	4.150% Series SSS due 2048		400,000,000		4,072,043		1,768,000	05/17/2018	05/15/2048	05/17/2018	05/15/2048	400,000,000	16,600,000
16	4.100% Series TTT due 2049		400,000,000		4,345,931		420,000	05/31/2019	06/15/2049	05/31/2019	06/15/2049	400,000,000	16,400,000
17	3.320% Series UUU due 2050		400,000,000		4,464,828		532,000	04/07/2020	04/15/2050	04/07/2020	04/15/2050	400,000,000	13,280,000
18	1.700% Series VVV due 2030		800,000,000		6,688,168		1,392,000	09/28/2020	10/01/2030	09/28/2020	10/01/2030	800,000,000	13,600,000
19	2.950% Series WWW due 2051 (D.08-07-029, D.18-02-012, D.20-04-015 issued August 13, 2021)		750,000,000		8,236,055		4,740,000	08/13/2021	08/15/2051	08/13/2021	08/15/2051	750,000,000	8,481,250
20	Subtotal		(a) 7,000,000,000		(b) 67,631,522		25,198,500					6,417,859,000	237,293,427
21	Reacquired Bonds (Account 222)
22
23
24
25	Subtotal
26	Advances from Associated Companies (Account 223)
27
28
29
30	Subtotal
31	Other Long Term Debt (Account 224)
32
33
34
35	Subtotal
33	TOTAL		7,000,000,000									6,417,859,000	237,293,427

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: BondsPrincipalAmountIssued

D.93-09-069 - At December 2021 total remaining authority for new preferred debt under this decision was $48,360,000.

D.04-01-009 - At December 2021 total remaining authority for new preferred debt under this decision was $4,000,000 and $76,000,000 for rollover preferred.

D.06-05-015 - At December 2021 total remaining authority for new preferred debt under this decision was $200,000,000.

D.08-07-029 - In July 2008, SDG&E received authority from the California Public Utilities Commission to issue $687,000,000 of new debt and $413,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $123,130,000 due 2051. At December 2021 there was no remaining authority.

D.10-10-023 - At December 2021 total remaining authority for new preferred debt under this decision was $150,000,000.

D.18-02-012 - In February 2018, SDG&E received authority from the California Public Utilities Commission to issue $750,000,000 of new debt and $300,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $226,870,000 due 2051. At December 2021 total remaining authority for rollover debt under this decision was $73,130,000.

D.20-04-015 - In April 2020, SDG&E received authority from the California Public Utilities Commission to issue $2,300,000,000 of new debt and $730,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $400,000,000 due 2051. At December 2021 total remaining authority under this decision was $1,115,430,000 for new debt, $803,130,000 for rollover debt, $402,360,000 for new preferred and $76,000,000 for rollover referred.

(b) Concept: BondIssuanceExpense


Expense	$	67,631,522
Discount	$	25,198,500
Account 221	$	92,830,022

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	(a) 819,252,902
2	Reconciling Items for the Year
3
4	Taxable Income Not Reported on Books
5	Contributions in Aid of Construction	45,504,230
6	Other (Itemized within footnote)	(b) 4,454
9	Deductions Recorded on Books Not Deducted for Return
10	Book Depreciation on Fixed Assets	868,811,119
11	Federal and State Taxes	200,774,455
12	Amortization and Interest Capitalized	80,195,522
13	Other (Itemized within footnote)	(c) 21,810,068
14	Income Recorded on Books Not Included in Return
15	Allowance for Funds Used During Construction	105,742,795
16	Unbilled Revenue	14,025,186
17	Restricted Stock
18	Other (Itemized within footnote)	(d) 18,268,289
19	Deductions on Return Not Charged Against Book Income
20	Tax Depreciation on Fixed Assets	676,357,985
21	Regulatory Balancing Accounts	333,502,904
22	Elec & Gas Repairs	246,883,137
23	Software Development Costs	196,307,485
24	Removal Costs	98,601,896
25	Current State Tax Deduction	34,571,461
26	Other (Itemized within footnote)	(e) 34,486,354
27	Federal Tax Net Income	277,605,255
28	Show Computation of Tax:
29	Federal Tax @ 21%	58,297,104
30	Deferred Taxes	82,998,127
31	Tax Credits and Other Adjustments (net)	18,686,454
32	Fed Discrete Taxes	11,084,658
33	Total Federal Income Tax Expense	133,693,435

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: NetIncomeLoss

South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

(b) Concept: TaxableIncomeNotReportedOnBooks


Fuel Tax Credit Addback	$	4,454
	$	4,454

(c) Concept: DeductionsRecordedOnBooksNotDeductedForReturn


Contingency Book Reserves	$	9,495,458
Accrued Vacation	7,226,744
Lobbying	970,582
Miscellaneous Expenses	4,117,284
	$	21,810,068

(d) Concept: IncomeRecordedOnBooksNotIncludedInReturn


Keyman Life Insurance	$	(7,593,458)
Deferred Construction Revenue	(7,167,913)
Restricted Stock	(1,625,688)
SONGS Decommissioning Costs	(1,364,236)
Book Gain on Sale of Utility Property	(516,994)
	$	(18,268,289)

(e) Concept: DeductionsOnReturnNotChargedAgainstBookIncome


Abandonment Loss	$	(13,759,744)
CARES Act Payroll tax deferral	(10,866,733)
Bad Debt	(7,291,263)
Property Taxes	(1,770,135)
Deferred Debits/Credits	(575,263)
Miscellaneous Inc/(Ded)	(223,216)
	$	(34,486,354)

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
					BALANCE AT BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1	Taxes on Income (Note 3)	Federal Tax	CA	2021	3,501,695	(a) 0	34,763,477	46,057,044	6,171,192	0	1,620,680	53,377,736			18,614,259
2	Retirement (Note 4)	Federal Tax	CA	2021	10,758,243	0	33,414,426	34,920,837		9,251,832	0	(e) 12,453,808			(g) 20,960,618
3	Unemployment (Note 4)	Federal Tax	CA	2021	42,425	0	183,992	219,687		6,730	0	137,011			46,981
4	Medicare (Note 4)	Federal Tax	CA	2021	110,376	0	10,180,546	10,128,813		162,109	0	3,794,362			6,386,184
5	Fuel Tax	Federal Tax	CA	2021	0	95,743	561,274	575,769		0	110,238				561,274
6	Subtotal Federal Tax				14,412,739	(b) 95,743	79,103,715	91,902,150	(d) 6,171,192	9,420,671	1,730,918	(f) 69,762,917			9,340,798
7	Franchise (Note 3)	State Tax	CA	2021	0	(c) 495,861	12,874,523	20,734,748	2,645,637	0	5,710,449	22,323,632			9,449,109
8	Unemployment (Note 4)	State Tax	CA	2021	148,509	0	528,564	658,410		18,663	0	393,599			134,965
9	Sales and Use (Note 2)	State Tax	CA	2021	14,485	0	1,440,174	1,116,892		337,767	0				1,440,174
10	Fuel Tax	State Tax	CA	2021	7,400	0	16,480	23,880		0	0				16,480
11	Subtotal State Tax				170,394	495,861	14,859,741	22,533,930	2,645,637	356,430	5,710,449	22,717,231			7,857,490
12	Ad Valorem (Note 1)	Local Tax	CA	2021	0	840,997	183,585,501	204,392,592	20,806,949	0	841,139	158,074,376			25,511,125
13	Sales and Use (Note 2)	Local Tax	CA	2021	12,232	0	420,052	325,760		106,524	0				420,052
14	Business License	Local Tax	CA	2021	0	0	68,282	68,282		0	0	63,080			5,202
15	Subtotal Local Tax				12,232	840,997	184,073,835	204,786,634	20,806,949	106,524	841,139	158,137,456			25,936,379
16					0	0				0	0
17	Subtotal Other Tax				0	0				0	0
18	Subtotal Property Tax				0	0				0	0
19	Subtotal Real Estate Tax				0	0				0	0
20	Subtotal Unemployment Tax				0	0				0	0
21	Subtotal Sales And Use Tax				0	0				0	0
22	Subtotal Income Tax				0	0				0	0	0
23	Subtotal Excise Tax				0	0				0	0
24	Subtotal Fuel Tax				0	0				0	0
25	Subtotal Federal Insurance Tax				0	0				0	0
26	Subtotal Franchise Tax				0	0				0	0
27	Subtotal Miscellaneous Other Tax				0	0				0	0
28	Subtotal Other Federal Tax				0	0				0	0
29	Subtotal Other State Tax				0	0				0	0
30	Subtotal Other Property Tax				0	0				0	0
31	Subtotal Other Use Tax				0	0				0	0
32	Subtotal Other Advalorem Tax				0	0				0	0
33	Subtotal Other License And Fees Tax				0	0				0	0
34	Subtotal Payroll Tax				0	0				0	0
35	Subtotal Advalorem Tax				0	0				0	0
36	Subtotal Other Allocated Tax				0	0				0	0
37	Subtotal Severance Tax				0	0				0	0
38	Subtotal Penalty Tax				0	0				0	0
39	Subtotal Other Taxes And Fees				0	0				0	0
40	TOTAL				(h) 14,595,365	1,432,601	278,037,291	319,222,714	29,623,778	9,883,625	8,282,506	250,617,604			27,419,687

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: PrepaidTaxes


Description	Adjustment Amount	FERC 190	FERC 283	FERC 171	FERC 237

Utilization of Net Operating Loss
Balance Sheet Reclassification Due to FIN 48 Liabilities	(6,171,186)		6,171,186
Balance Sheet Reclassification Due to FIN 48 Liabilities - Interest

Total - Federal Income Tax Adjustment	(6,171,186)	—	6,171,186	—	—

(b) Concept: PrepaidTaxes

This adjustment is for a portion of property taxes paid on construction work in progress. The property tax charged during the year was reduced and capitalized to certain assets under construction.

(c) Concept: PrepaidTaxes


Description	Adjustment Amount	FERC 190	FERC 283	FERC 171	FERC 237

Balance Sheet Reclassification Due to FIN 48 Liabilities	(2,645,634)	2,645,634

Total - California Corporation Franchise Tax Adjustment	(2,645,634)	2,645,634	—	—	—

(d) Concept: TaxAdjustments

Property tax expense of $632,254 and $67,128 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines are deducted and moved to column (l).

(e) Concept: TaxesAccruedPrepaidAndCharged

Payroll tax expense of $21,778 and $2,438 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines are deducted and moved to column (l).

(f) Concept: TaxesAccruedPrepaidAndCharged

Includes property tax expense of $632,254 and $67,128 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines.

(g) Concept: TaxesIncurredOther

Includes payroll tax expense of $21,778 and $2,438 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines.

(h) Concept: TaxesAccrued

Note 1:

Ad Valorem taxes are allocated based on type of assets in each taxing jurisdiction.

Note 2:

Sales and Use taxes are allocated based on the Common Allocation Factor.

Sales and Use tax adjustments in column "f" are to adjust carry forward balances from last year.

Note 3:

State and Franchise Tax and Federal Income Tax are charged to departments based on total taxable income generated by each department.

Note 4:

Retirement, Unemployment, and Medicare taxes are charged to departments as a percentage of total taxable labor charged.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%
3	4%
4	7%
5	10%
6	Various	13,377,869			411.4	271,798		13,106,071	25 to 30 years
8	TOTAL Electric (Enter Total of lines 2 thru 7)	13,377,869				(a) 271,798		13,106,071
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
11	Gas Utility Various				411.4				25 to 30 years
47	OTHER TOTAL
48	GRAND TOTAL	13,377,869						13,106,071

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAmount

Account 255 transmission related amortization of investment tax credits allocated to current year income is $264,763.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	CIAC/CAC Tax Gross-Ups	68,553,578	456/495	12,521,108	13,656,407	69,688,877
2	Amortized over various 31 yr lives
3	SONGS Mitigation	35,704,361	182.3	858,869	8,208,288	43,053,780
4	OIL Insurance Limited	12,393,778	182.3	172,801		12,220,977
5	Sunrise Fire Mitigation Liability	117,840,601	182.3	3,718,291	4,415,575	118,537,885
6	Citizens Lease	83,292,528	242	3,736,060		79,556,468
7	Greenhouse Gas Obligations		158	26,730,880	57,693,422	30,962,542
8	Miscellaneous	38,768,619	Various	34,186,934	22,076,370	26,658,055
9	Wildfire Fund Obligations	74,889,108	242	12,900,000	1,926,360	63,915,468
47	TOTAL	431,442,573		94,824,943	107,976,422	444,594,052

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
For other (Specify),include deferrals relating to other income and deductions.
Use footnotes as required.

CHANGES DURING YEAR

ADJUSTMENTS

Debits

Credits

Line No.

Account

(a)

Balance at Beginning of Year

(b)

Amounts Debited to Account 410.1

(c)

Amounts Credited to Account 411.1

(d)

Amounts Debited to Account 410.2

(e)

Amounts Credited to Account 411.2

(f)

Account Credited

(g)

Amount

(h)

Account Debited

(i)

Amount

(j)

Balance at End of Year

(k)

1

Accelerated Amortization (Account 281)

2

Electric

3

Defense Facilities

4

Pollution Control Facilities

5

Other

5.1

Other (provide details in footnote):

8

TOTAL Electric (Enter Total of lines 3 thru 7)

9

Gas

10

Defense Facilities

11

Pollution Control Facilities

12

Other

12.1

Other (provide details in footnote):

15

TOTAL Gas (Enter Total of lines 10 thru 14)

16

Other

16.1

Other

16.2

Other

17

TOTAL (Acct 281) (Total of 8, 15 and 16)

18

Classification of TOTAL

19

Federal Income Tax

20

State Income Tax

21

Local Income Tax

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	(a) 1,577,151,826	97,001,290	71,673,287			Various	46,837,720	Various	84,390,108	1,640,032,217
3	Gas	172,724,264	11,827,148	9,360,846			Various	6,257,770	Various	20,487,745	(b) 189,420,541
4	Other (Specify)	0
5	Total (Total of lines 2 thru 4)	1,749,876,090	108,828,438	81,034,133				53,095,490		104,877,853	1,829,452,758
6		0
7	Non Utility	85,090,237			7,245,127	450,732			182.3	22,796,247	114,680,879
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,834,966,327	108,828,438	81,034,133	7,245,127	450,732		53,095,490		127,674,100	1,944,133,637
10	Classification of TOTAL
11	Federal Income Tax	1,483,061,519	80,655,424	68,891,083	5,098,782	450,732		36,986,634		90,055,564	1,552,542,840
12	State Income Tax	351,904,808	28,173,016	12,143,048	2,146,345			16,108,856		37,618,532	391,590,797
13	Local Income Tax	0

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

Account 282 electric balance at the beginning of the year reflects a reduction for (amortization) of non-Citizens transmission related excess deferred federal income taxes in the amount of ($4,309,561).

Account 282 electric balance at the beginning of the year reflects a reduction for (amortization) of Citizens transmission related excess deferred federal income taxes in the amount of ($180,826).

Account 282 non-Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $732,250,020.

Account 282 Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $12,022,715.

Account 282 Citizens SX-PQ transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $3,028,935.

Account 282 non-Citizen transmission related excess deferred income tax reserve at the beginning of the year was $376,621,256.

Account 282 Citizen transmission related excess deferred income tax reserve at the beginning of the year was $8,318,012.

(b) Concept: AccumulatedDeferredIncomeTaxesOtherProperty

Account 282 electric balance at the end of the year reflects a reduction for (amortization) of non-Citizens transmission related excess deferred federal income taxes in the amount of ($4,530,851).

Account 282 electric balance at the end of the year reflects a reduction for (amortization) of Citizens transmission related excess deferred federal income taxes in the amount of ($180,826).

Account 282 non-Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $771,220,222.

Account 282 Citizens Sunrise transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $11,512,111.

Account 282 Citizens SX-PQ transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $3,145,258.

Account 282 non-Citizen transmission related excess deferred income tax reserve at the end of the year was $358,966,142.

Account 282 Citizen transmission related excess deferred income tax reserve at the end of the year was $8,137,186.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Electric	(a) 223,721,394	175,029,998	70,885,223			Various	57,610,964	Various	79,014,069	(b) 349,269,274
4		0									0
9	TOTAL Electric (Total of lines 3 thru 8)	223,721,394	175,029,998	70,885,223				57,610,964		79,014,069	349,269,274
10	Gas
11	Gas	28,049,918	13,149,204	1,331,771			Various	14,162,251	Various	17,305,845	45,674,487
12		0									0
17	TOTAL Gas (Total of lines 11 thru 16)	28,049,918	13,149,204	1,331,771				14,162,251		17,305,845	45,674,487
18	TOTAL Other	38,360,292			23,672	380,514	182.3	314,591	182.3	9,178,369	46,867,228
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	290,131,604	188,179,202	69,553,452	23,672	380,514		72,087,806		105,498,283	441,810,989
20	Classification of TOTAL
21	Federal Income Tax	198,737,105	133,501,998	52,350,041	23,672	267,788		49,903,217		72,171,446	301,913,175
22	State Income Tax	91,394,499	54,677,204	17,203,411		112,726		22,184,589		33,326,837	139,897,814
23	Local Income Tax	0
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

Account 283 transmission allocation related other deferred tax liability included in electric accumulated deferred income taxes at the beginning of the year was $7,906,429.

(b) Concept: AccumulatedDeferredIncomeTaxesOther

Account 283 transmission allocation related other deferred tax liability included in electric accumulated deferred income taxes at the end of the year was $7,891,472.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Deferred Taxes Payable in rates	911,640,379	Various	36,742,482	2,351,268	877,249,165
2	Asset Retirement Obligations	548,154,797	230	14,383,252	15,604,908	549,376,453
3	Balancing Account Overcollections	749,561,463	456/495	108,188,429	9,531,930	650,904,964
4	Electric / Gas Derivatives	128,289,761	175.1	45,586,393	70,033	82,773,401
5	PBOP Benefits	20,085,874	Various	10,616,874		9,469,000
41	TOTAL	2,357,732,274		215,517,430	27,558,139	2,169,772,983

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Electric Operating Revenues
The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	1,646,785,175	1,600,890,105	5,671,599	6,606,155	1,277,154	1,311,290
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	1,051,760,623	1,402,837,991	4,177,710	5,872,843	108,715	151,058
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	266,665,956	358,553,421	1,397,952	1,841,889	253	392
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	11,386,964	14,272,909	51,239	77,228	1,651	2,090
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	2,976,598,718	3,376,554,426	11,298,500	14,398,115	1,387,773	1,464,830
11	SalesForResaleAbstract (447) Sales for Resale	559,623,423	414,730,041	9,195,146	10,344,942
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	3,536,222,141	3,791,284,467	20,493,646	24,743,057	1,387,773	1,464,830
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	3,536,222,141	3,791,284,467	20,493,646	24,743,057	1,387,773	1,464,830
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(a) 94,041,045	(d) 100,035,626
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	(b) 4,820,177	(e) 3,551,962
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 1,261,094,462	(f) 849,991,545
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	316,575,181	271,027,123
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	1,676,530,865	1,224,606,256
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	5,212,753,006	5,015,890,723
Line12, column (b) includes $ of unbilled revenues.
Line12, column (d) includes MWH relating to unbilled revenues

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues


Description
San Diego Franchise Fee Surcharge	$	87,362,890
Net Energy Metering	3,609,268
Service Establishment	2,020,918
Mover Service Charge	547,298
Late Payment Charge	(443)
Other*	501,114
	$	94,041,045

* Individual balances are less than $250,000

(b) Concept: RentFromElectricProperty

Includes Transmission Revenue Credits of $447,000

(c) Concept: OtherElectricRevenue


Description
Direct Access	$	352,834,389
Cap and Trade Revenues	161,825,842
Balancing Accounts	208,448,901
CCA T&D Revenue	399,836,861
Federal Project Management	7,649,899
PUC Reimbursement Fee	22,235,549
CIAC Income Tax	5,895,373
LCFS Rec Credits	16,268,835
Shared Assets	7,215,238
Generation Trans. Interconnection Rev.	2,549,526
Unbilled Revenue	81,541,342
Litigation	(3,500,000)
Government Turnkey	(6,666,264)
Employee Transfer Fees	538,749
Joint Pole Activity	2,906,109
Other*	1,514,113
	$	1,261,094,462

* Individual balances are less than $250,000

* Includes Transmission Revenue Credits of $4,418,332

(d) Concept: MiscellaneousServiceRevenues


Description
San Diego Franchise Fee Surcharge	$	91,351,964
Service Establishment	4,059,306
Net Energy Metering	2,809,830
Late Payment Charge	1,181,049
Mover Service Charge	150,041
Other*	483,436
	$	100,035,626

* Individual balances are less than $250,000

(e) Concept: RentFromElectricProperty

Includes Transmission Revenue Credits of $208,760

(f) Concept: OtherElectricRevenue


Description
Direct Access	$	287,858,282
Cap and Trade Revenues	105,107,923
Balancing Accounts	385,160,293
CCA T&D Revenue	11,281,401
Federal Project Management	17,175,228
CIAC Income Tax	6,006,110
LCFS Rec Credits	24,346,377
Shared Assets	3,802,823
PUC Reimbursement Fee	13,015,817
Government Turnkey	(16,044,837)
Unbilled Revenue	4,565,763
Joint Pole Activity	3,589,710
Generation Trans. Interconnection Rev.	2,587,281
Employee Transfer Fees	567,500
Other*	971,874
	$	849,991,545

* Individual balances are less than $250,000

* Includes Transmission Revenue Credits of $3,501,419

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	DR	1,303,978	351,838,087	296,860	4,393	0.2698
2	DRTOU	4,016,918	1,208,300,242	951,343	4,222	0.3008
3	EVTOU	181,006	43,852,622	22,331	8,106	0.2423
4	DRLI
5	DM	36,989	11,167,368	3,730	9,917	0.3019
6	DS	16,051	4,106,408	218	73,628	0.2558
7	DT	110,138	25,243,453	367	300,104	0.2292
8	OL-1	6,346	2,178,961	2,272	2,793	0.3434
9	DWL	173	98,034	33	5,242	0.5667
41	TOTAL Billed Residential Sales	5,671,599	1,646,785,175	1,277,154	4,441	0.2904
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	5,671,599	1,646,785,175	1,277,154	4,441	0.2904

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	A	41,171	8,078,333	4,560	9,029	0.1962
2	ASTOD	355,168	78,928,703	28,920	12,281	0.2222
3	ATOU	76,685	16,910,755	1,495	51,294	0.2205
4	AD
5	UM	13,590	3,744,527	79	172,025	0.2755
6	PA
7	PAT1	272,365	51,805,082	4,603	59,171	0.1902
8	AL-TOU	2,252,922	606,648,936	9,487	237,475	0.2693
9	SPSS			1
10	DG	192,671	23,979,631	462
11	OL-1	1,107	364,219	397	2,788	0.3290
12	OLTOU	1,383	319,755	27	51,222	0.2312
13	TOUA	970,648	260,980,682	58,684	16,540	0.2689
41	TOTAL Billed Small or Commercial	4,177,710	1,051,760,623	108,715	38,428	0.2518
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)
43	TOTAL Small or Commercial	4,177,710	1,051,760,623	108,715	38,428	0.2518

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	DG	134,480	5,774,052	19	7,077,895	0.0429
2	AL-TOU	1,205,038	243,875,222	221	5,452,661	0.2024
3	A6-TOU	58,434	17,016,682	13	4,494,923	0.2912
41	TOTAL Billed Large (or Ind.) Sales	1,397,952	266,665,956	253	5,525,502	0.1908
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)
43	TOTAL Large (or Ind.)	1,397,952	266,665,956	253	5,525,502	0.1908

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41	TOTAL Billed Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	LS1	13,555	4,957,799	630	21,516	0.3658
2	LS2	36,925	6,305,434	872	42,345	0.1708
3	LS3	759	123,731	149	5,094	0.1630
41	TOTAL Billed Public Street and Highway Lighting	51,239	11,386,964	1,651	31,035	0.2222
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL	51,239	11,386,964	1,651	31,035	0.2222

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES OF ELECTRICITY BY RATE SCHEDULES
Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	11,298,500	2,976,598,718	1,387,773	8,141	0.2635
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43	TOTAL - All Accounts	11,298,500	2,976,598,718	1,387,773	8,141	0.2635

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SALES FOR RESALE (Account 447)
Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326). Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years. OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k). In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	California ISO						9,136,196		501,451,464		501,451,464
2	City of Escondido (Rincon Hydro Plant)	SF	FERC Vol. 10				90		17,505		17,505
3	Calpine Energy Services LP	SF	FERC Vol. 10				0	67,499			67,499
4	City of Burbank	SF	FERC Vol. 10				2,400		138,800		138,800
5	City of Glendale Water and Power	SF	FERC Vol. 10				800		21,600		21,600
6	City of Lancaster	SF	FERC Vol. 10				0	3,375,135			3,375,135
7	City of San Jose	SF	FERC Vol. 10				0	3,149,216			3,149,216
8	Clean Energy Alliance	SF	FERC Vol. 10				0	7,674,362			7,674,362
9	Direct Energy Business Marketing	SF	FERC Vol. 10				20,837		332,142	(a) 332,142
10	EDF Trading North America LLC	SF	FERC Vol. 10				0	2,598,505			2,598,505
11	Exelon Generation Company LLC	SF	FERC Vol. 10				0	6,626,084		(b) 2,308,304	8,934,388
12	Los Angeles Dept. of Water & Power	SF	FERC Vol. 10				5,600		435,680		435,680
13	Pacific Gas & Electric Company	SF	FERC Vol. 10				0	1,551,208			1,551,208
14	Peninsula Clean Energy Authority	SF	FERC Vol. 10				19,000		264,100	(c) 264,100
15	Pioneer Community Energy	SF	FERC Vol. 10				0	1,500,090			1,500,090
16	Portland General Electric	SF	FERC Vol. 10				400		17,600		17,600
17	Powerex Corporation	SF	FERC Vol. 10				3,200		112,000		112,000
18	Recurrent Energy Development	SF	FERC Vol. 10				0	120,000			120,000
19	Sacramento Municipal Utility District	SF	FERC Vol. 10				5,423		81,345	(d) 81,345
20	San Diego Community Power	SF	FERC Vol. 10				0	16,159,620			16,159,620
21	Silicon Valley Clean Energy Authority	SF	FERC Vol. 10				0	1,891,149			1,891,149
22	Sonoma Clean Power Authority	SF	FERC Vol. 10				0	1,723,101			1,723,101
23	Southern California Edison	SF	FERC Vol. 10				800	8,454,501	88,000		8,542,501
24	TransAlta Energy Marketing US	SF	FERC Vol. 10				400		142,000		142,000
15	Subtotal - RQ
16	Subtotal-Non-RQ						9,195,146	54,890,470	501,747,062	2,985,891	559,623,423
17	Total						9,195,146	54,890,470	501,747,062	2,985,891	559,623,423

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: OtherChargesRevenueSalesForResale

Contract to sell Renewable Energy Credits

(b) Concept: OtherChargesRevenueSalesForResale

Contract to sell Renewable Energy Credits

(c) Concept: OtherChargesRevenueSalesForResale

Contract to sell Renewable Energy Credits

(d) Concept: OtherChargesRevenueSalesForResale

Contract to sell Renewable Energy Credits

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	1,945,733	2,071,055
5	FuelSteamPowerGeneration (501) Fuel	140,396,456	85,839,459
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	102
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.	934
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	1,017,715	357,033
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	6,536,502	6,566,199
11	RentsSteamPowerGeneration (507) Rents	35,143	35,143
12	Allowances (509) Allowances
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	149,932,585	94,868,889
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering		588
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	183,550	103,659
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	2,369,531	2,359,936
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	582,672	352,104
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	7,598,822	4,795,725
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	10,734,575	7,612,012
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	160,667,160	102,480,901
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering		9,300
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses	2,190,736	3,463,925
32	RentsNuclearPowerGeneration (525) Rents	113,532
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)	2,077,204	3,473,225
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering	150,432	177,358
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment		12,232
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant	2,352
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)	152,784	165,126
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)	2,229,988	3,308,099
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering
45	WaterForPower (536) Water for Power
46	HydraulicExpenses (537) Hydraulic Expenses
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses
49	RentsHydraulicPowerGeneration (540) Rents
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	260,143	308,942
63	Fuel (547) Fuel	1,488,814	3,046,408
64	GenerationExpenses (548) Generation Expenses
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	3,815,706	5,092,124
66	RentsOtherPowerGeneration (550) Rents	306
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	5,564,969	8,447,474
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures	64,982	125,311
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	6,900,692	7,477,951
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant	13,744,866	6,360,616
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	20,580,576	13,963,878
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	26,145,545	22,411,352
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	1,684,386,068	1,712,801,101
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	1,573,613	2,165,143
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	6,938,917	5,914,678
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	1,692,898,598	1,720,880,922
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	1,881,941,291	1,849,081,274
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	9,551,648	6,646,021
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability	872,180	818,282
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	1,592,020	1,544,638
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling	122,504	132,130
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	3,844,368	5,200,324
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	84,087	82,101
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies		2,022
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	2,540,191	3,058,271
93	StationExpensesTransmissionExpense (562) Station Expenses	8,258,672	6,458,357
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	10,149,410	9,764,840
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	58,883	51,420
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	17,591,239	14,538,153
98	RentsTransmissionElectricExpense (567) Rents	3,946,818	2,779,304
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	58,612,020	51,075,863
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	1,949,278	1,772,731
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	529,448	567,231
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	1,034,457	857,038
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	3,015,796	1,623,687
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	52	65
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant	173,122	156,270
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	19,573,862	15,716,966
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	24,432,908	26,863,352
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	423,899	1,113,175
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	11,490	5,599
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	51,144,312	48,676,114
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	109,756,332	99,751,977
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services	2,743,013	3,171,002
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	2,743,013	3,171,002
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)	2,743,013	3,171,002
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	26,150,160	26,626,900
135	LoadDispatching (581) Load Dispatching	1,417,246	2,959,973
136	StationExpensesDistribution (582) Station Expenses	4,666,542	6,583,947
137	OverheadLineExpenses (583) Overhead Line Expenses	7,633,427	12,787,071
138	UndergroundLineExpenses (584) Underground Line Expenses	5,508,523	6,676,999
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	840,442	652,415
140	MeterExpenses (586) Meter Expenses	11,779,667	11,116,044
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	4,446,868	5,133,100
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	87,876,495	61,840,999
143	RentsDistributionExpense (589) Rents	310,830	473,746
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	150,630,200	134,851,194
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	829,325	2,299,907
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	150	170
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	6,283,430	4,389,418
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	108,643,725	149,925,139
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	16,914,676	17,854,802
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	239,501	5,658
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	7,410	220,135
153	MaintenanceOfMeters (597) Maintenance of Meters	1,684,599	1,531,236
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	4,382,733	5,587,114
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	138,985,549	181,813,579
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	289,615,749	316,664,773
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	396	766
160	MeterReadingExpenses (902) Meter Reading Expenses	2,246,141	2,075,012
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	67,040,791	43,546,162
162	UncollectibleAccounts (904) Uncollectible Accounts	11,370,178	40,294,644
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	261,608	266,677
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	80,919,114	86,183,261
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	187,561,814	132,620,477
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses	747,786	821,722
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	1,563,859	1,872,681
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	189,873,459	135,314,880
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	155,328	157,477
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	155,328	157,477
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	62,282,647	46,411,109
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	33,307,565	28,861,000
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	20,277,083	18,872,382
184	OutsideServicesEmployed (923) Outside Services Employed	108,586,773	108,535,259
185	PropertyInsurance (924) Property Insurance	8,615,717	8,310,402
186	InjuriesAndDamages (925) Injuries and Damages	215,579,218	181,130,339
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	56,506,011	62,304,380
188	FranchiseRequirements (927) Franchise Requirements	128,579,841	130,506,765
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	35,379,656	27,995,793
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	12,933,801	2,772,785
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	66,135	204,155
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	10,538,715	2,511,055
193	RentsAdministrativeAndGeneralExpense (931) Rents	12,351,503	10,939,305
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	638,582,897	585,656,085
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	18,209,169	9,293,298
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	656,792,066	594,949,383
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	3,211,485,696	3,085,274,027

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment. AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	Alta Oak Realty	LU	FERC Vol. 10				361,366					(a) 357,954	454	357,500
2	Arlington Valley Solar II LLC	LU	FERC Vol. 10				47,377					(b) 42,070,922	833,224	42,904,146
3	California ISO						11,274,753					(c) 705,571,949	16,853,857	688,718,092
4	Calipatria LLC	LU	FERC Vol. 10				47,377					(d) 3,506,449	181,540	3,687,989
5	Calpeak Power LLC	OS					495				2,565,019			2,565,019
6	Campo Verde Solar LLC	LU	FERC Vol. 10				347,952					(e) 42,378,458	141,231	42,519,689
7	Carlsbad Energy Center LLC	LU	FERC Vol. 10				441,732				103,696,176	33,636,264		137,332,440
8	Cascade Solar LLC	LU	FERC Vol. 10				53,541					(f) 4,530,821	5,671	4,525,150
9	Catalina Solar LLC	LU	FERC Vol. 10				250,128					(g) 33,699,692	25,302	33,674,390
10	Centinela Solar Energy LLC	LU	FERC Vol. 10				373,289					(h) 51,438,888	271,962	51,710,850
11	Centinela Solar Energy 2 LLC	LU	FERC Vol. 10				132,717					18,304,624	72,445	18,377,069
12	City of Escondido (Bear Valley Hydro)	LU	FERC Vol. 10				496				6,644	22,826		29,470
13	City of Oceanside (San Francisco Peak Hydro)	LU	FERC Vol. 10				147				1,617	10,227		11,844
14	Clean Power Alliance of SoCal	LU	FERC Vol. 10				0				1,594,294			1,594,294
15	Coram Energy LLC	LU	FERC Vol. 10				24,624					(i) 2,539,412	2,464	2,536,948
16	CP Kelco US Inc	LU	FERC Vol. 10				7,656				80,861	457,447		538,308
17	CSolar IV South LLC	LU	FERC Vol. 10				292,930					(j) 40,753,334	309,065	41,062,399
18	CSolar IV West LLC	LU	FERC Vol. 10				402,034					(k) 44,077,187	137,062	44,214,249
19	Desert Green Solar Farm LLC	LU	FERC Vol. 10				11,989					(l) 1,676,280	2,075	1,674,205
20	El Cajon Energy Center (Tolling)	LU	FERC Vol. 10				6,659				7,269,412	810,146		8,079,558
21	Energia Sierra Juarez US LLC	LU	FERC Vol. 10				426,207					(m) 43,780,556	440,695	44,221,251
22	Escondido Energy Center LLC	LU	FERC Vol. 10				8,675				7,774,511	942,127		8,716,638
23	Goal Line LP	LU	FERC Vol. 10				17,362				11,109,931	1,284,369		12,394,300
24	Grossmont Hospital Corporation	LU	FERC Vol. 10				3,063				14,280	172,878		187,158
25	HL Power Company LP	LU	FERC Vol. 10				149,030					15,751,724		15,751,724
26	Imperial Valley Solar I LLC (Mount Signal)	LU	FERC Vol. 10				370,438					(n) 43,243,088	153,095	43,396,183
27	Kumeyaay Wind LLC	LU	FERC Vol. 10				152,648				180,360	(o) 7,824,988	147,421	8,152,769
28	Manzana Wind LLC	LU	FERC Vol. 10				293,789					13,959,598		13,959,598
29	Maricopa West Solar PV LLC	LU	FERC Vol. 10				36,899					(p) 2,522,526	3,772	2,518,754
30	Midway Solar	LU	FERC Vol. 10				50,544				93	(q) 2,401,500	174,368	2,575,961
31	MM Prima Deshecha Energy LLC	LU	FERC Vol. 10				44,919					318,413		318,413
32	MM San Diego LLC (Miramar RAM)	LU	FERC Vol. 10				27,086					2,096,183		2,096,183
33	Morgan Stanley Capital Group	LU	FERC Vol. 10				750,322
34	Naturener Glacier Wind Energy 1 LLC	EX							263,833	263,833		5,540,490		5,540,490
35	Naturener Glacier Wind Energy 2 LLC	EX							283,544	283,544		8,506,313		8,506,313
36	Naturener Rim Rock Wind Energy LLC	EX							644,935	644,935		28,370,668		28,370,668
37	NLP Valley Center Solar LLC	LU	FERC Vol. 10				5,831					(r) 642,129	588	641,541
38	NLP Granger A82 LLC	LU	FERC Vol. 10				7,259					(s) 768,221	734	767,487
39	Oak Creek Wind Power LLC	LU	FERC Vol. 10				265					(t) 55,047	126	54,921
40	Ocotillo Express LLC	LU	FERC Vol. 10				439,172					(u) 42,636,820	37,529	42,599,291
41	Olivenhain Muni Water District	LU	FERC Vol. 10				869					108,974		108,974
42	Orange Grove Energy Center (Tolling)	LU	FERC Vol. 10				14,858				17,051,016	1,001,117		18,052,133
43	Otay Mesa Energy Center (Tolling)	LU	FERC Vol. 10				0				49,670,244		40,685	49,710,929
44	Pacific Wind Lessee LLC	LU	FERC Vol. 10				332,125					(v) 38,083,355	227,924	38,311,279
45	Pio Pico Energy Center	LU	FERC Vol. 10				75,539				66,587,956	5,891,649		72,479,605
46	San Diego County Water Authority -Olivenhain-Hodges	LU	FERC Vol. 10				20,497				2,663,644	415,700		3,079,344
47	San Gorgonio Westwinds II LLC	LU	FERC Vol. 10				37,822					(w) 2,619,971	3,651	2,616,320
48	San Marcos Energy LLC	LU	FERC Vol. 10				11,827				1,296	1,388,365		1,389,661
49	SG2 Imperial Valley LLC	LU	FERC Vol. 10				423,602				1,081,800	(x) 30,216,143	1,889,859	33,187,802
50	Sol Orchard 20 LLC (Ramona 1)	LU	FERC Vol. 10				4,529					(y) 607,743	459	607,284
51	Sol Orchard 21 LLC (Ramona 2)	LU	FERC Vol. 10				11,784					(z) 1,583,764	1,075	1,582,689
52	Sol Orchard 22 LLC (Valley Center 1)	LU	FERC Vol. 10				5,651					(aa) 760,836	568	760,268
53	Sol Orchard 23 LLC (Valley Center 2)	LU	FERC Vol. 10				11,895					(ab) 1,602,650	1,194	1,601,456
54	Solar Borrego LLC	LU	FERC Vol. 10				69,557					(ac) 9,575,922	418,887	9,994,809
55	Sycamore Energy 1 LLC	LU	FERC Vol. 10				6,232				689	733,744		733,055
56	Sycamore Energy 2 LLC	LU	FERC Vol. 10				18,071				1,911	1,550,868		1,552,779
57	Tallbear Seville LLC	LU	FERC Vol. 10				60,747					(ad) 4,896,973	147,954	5,044,927
58	TransAlta Energy Marketing	LU	FERC Vol. 10				70,346					3,593,911		3,593,911
59	Yuma Co-generator Association	LU	FERC Vol. 10				70,346				10,073,807	9,227,842		19,301,649
60	Calpine Energy Services	SF	FERC Vol. 10								212,140	2,326,478		2,538,618
61	Elk Hills Power, LLC	SF	FERC Vol. 10								10,193			10,193
62	Marin Clean Energy	SF	FERC Vol. 10								10,678			10,678
63	Morgan Stanley Capital Group Inc	SF	FERC Vol. 10									26,473,587		26,473,587
64	Pacific Gas & Electric Co.	SF	FERC Vol. 10								67,725			67,725
65	Peninsula Clean Energy Authority	SF	FERC Vol. 10								58,000			58,000
66	Sempra Gas & Power Marketing LLC	SF	FERC Vol. 10								25,587,552			25,587,552
67	Sentinel Energy	SF	FERC Vol. 10								3,290,212			3,290,212
68	Southern California Edison Company	SF	FERC Vol. 10								90,750			90,750
69	Valley Center Storage I	SF	FERC Vol. 10								678,285			678,285
70	Valley Center Storage II	SF	FERC Vol. 10								1,808,719			1,808,719
71	Vista Energy Storage	SF	FERC Vol. 10								803,962	0		803,962
72	Procurement software											(ae) 0
73	Broker Fees	OS										(af) 0	12,000	12,000
74	Hedging Activity	OS										(ag) 0	221,314	221,314
75	Columbia Power Consulting	OS										(ah) 0	15,082,064	15,082,064
76	Montrose Air Quality Services	OS										(ai) 0	1,950	1,950
77	GHG Allowances	OS										(aj) 0	9,500	9,500
78	Misc. Adjustment											(ak) 0	17,043,480	17,043,480
79	Counterparty Deposits											(al) 0	2	2
80	Green Tariff Entries	OS										0	60,000	60,000
81												0
15	TOTAL						18,066,074	0	1,192,312	1,192,312	304,271,879	1,389,320,110	9,205,924	1,684,386,065

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(b) Concept: EnergyChargesOfPurchasedPower

Curtailment of 8,076 MWh and payment/penalties of $855,987. Forecasting fees.

(c) Concept: EnergyChargesOfPurchasedPower

CAISO allocated revenues and charges.

(d) Concept: EnergyChargesOfPurchasedPower

Curtailment of 3,622 MWh and payment/penalties of $198,574. Forecasting fees.

(e) Concept: EnergyChargesOfPurchasedPower

Curtailment of 2,325 MWh and payment/penalties of $185,033. Forecasting fees.

(f) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(g) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(h) Concept: EnergyChargesOfPurchasedPower

Curtailment of 3,351 MWh and payment/penalties of $410,210. Forecasting fees..

(i) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(j) Concept: EnergyChargesOfPurchasedPower

Curtailment of 3,260 MWh and payment/penalties of $356,638. Forecasting fees.

(k) Concept: EnergyChargesOfPurchasedPower

Curtailment of 2,811 MWh and payment/penalties of $214,115. Forecasting fees.

(l) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(m) Concept: EnergyChargesOfPurchasedPower

Curtailment of 6,059 MWh and payment/penalties of $526,155. Forecasting fees.

(n) Concept: EnergyChargesOfPurchasedPower

Curtailment of 2,436 MWh and payments/penalties of $190,204. Forecasting fees..

(o) Concept: EnergyChargesOfPurchasedPower

Curtailment of 1,655 MWh and payment/penalties of $73,732. Forecasting fees. OMS Curtailment.

(p) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(q) Concept: EnergyChargesOfPurchasedPower

Curtailment of 3,514 MWh and payment/penalties of $200,649. Forecasting fees.

(r) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(s) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(t) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(u) Concept: EnergyChargesOfPurchasedPower

Curtailment of 56 MWh and payments/penalties of $7,078. Forecasting fees.

(v) Concept: EnergyChargesOfPurchasedPower

Curtailment of 2,357 MWh and payments/penalties of $265,903. Forecasting fees.

(w) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(x) Concept: EnergyChargesOfPurchasedPower

Curtailment of 17,155 MWh and payments/penalties of $1,889,859.

(y) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(z) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(aa) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(ab) Concept: EnergyChargesOfPurchasedPower

Forecasting fees.

(ac) Concept: EnergyChargesOfPurchasedPower

Curtailment of 3,350 MWh and payment/penalties of $431,222. Forecasting fees.

(ad) Concept: EnergyChargesOfPurchasedPower

Curtailment of 484 MWh and payments/penalties of $176,561. Forecasting fees.

(ae) Concept: EnergyChargesOfPurchasedPower

Software & support

(af) Concept: EnergyChargesOfPurchasedPower

Contract administration expenses.

(ag) Concept: EnergyChargesOfPurchasedPower

Contract hedging activity.

(ah) Concept: EnergyChargesOfPurchasedPower

Engineering services.

(ai) Concept: EnergyChargesOfPurchasedPower

Environmental Services

(aj) Concept: EnergyChargesOfPurchasedPower

Amortization of GHG Allowances.

(ak) Concept: EnergyChargesOfPurchasedPower

EPA activity

(al) Concept: EnergyChargesOfPurchasedPower

Retained counterparty deposits

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
Report in column (i) and (j) the total megawatthours received and delivered.
In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

1

CAISO

N/A

OS

1

N/A

316,575,181

35

TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
	TOTAL

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	958,139
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Abandoned Projects	5,025,366
7	Cost of Financing	2,296,550
8	Other Expenses	2,258,660
46	MiscellaneousGeneralExpenses TOTAL	10,538,715

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
	A. Summary of Depreciation and Amortization Charges
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			15,043,789		15,043,789
2	Steam Production Plant	25,183,299				25,183,299
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional
5	Hydraulic Production Plant-Pumped Storage
6	Other Production Plant	27,822,430				27,822,430
7	Transmission Plant	210,002,612			1,949,507	211,952,119
8	Distribution Plant	317,767,256			2,067,623	319,834,879
9	Regional Transmission and Market Operation
10	General Plant	22,351,711				22,351,711
11	Common Plant-Electric	56,368,616		67,509,038		123,877,654
12	TOTAL	659,495,924		82,552,827	4,017,130	(a) 746,065,881

B. Basis for Amortization Charges
Account 404The amortization of Intangible Plant (software) is based on the anticipated useful life of the software project.Account 405The amortization of Land Rights is based on the anticipated useful lives of the rights-of-way.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	STEAM PRODUCTION
13	311-Desert Star	29.453	30 years	10.58	6.71	SQ	5 years, 3 months, 18 days
14	311-Palomar	61.963	30 years	2.3	3.81	SQ	15 years, 6 months
15	312-Desert Star	56.058	30 years	4.27	6.85	SQ	5 years, 3 months, 18 days
16	312-Palomar	107.51	30 years	2.3	3.36	SQ	15 years, 6 months
17	314-Desert Star	16.507	30 years	10.49	9.24	SQ	5 years, 3 months, 18 days
18	314-Palomar	116.366	30 years	1.41	3.6	SQ	15 years, 6 months
19	315-Desert Star	49.704	30 years	0.08	6.98	SQ	5 years, 3 months, 18 days
20	315-Palomar	37.258	30 years	0.32	3.42	SQ	15 years, 6 months
21	316-Desert Star	5.263	30 years	0.7	8	SQ	5 years, 3 months, 18 days
22	316-Palomar	57.48	30 years	0.25	4.49	SQ	15 years, 6 months
23	SUBTOTAL	537.562
24	OTHER PRODUCTION
25	341-CPEP	1.896	25 years	17.45	9.46	SQ	6 years, 6 months
26	341-Desert Star	3.005	30 years	30.74	16.58	SQ	5 years, 3 months, 18 days
27	341-Miramar	5.076	25 years	6.76	4.84	SQ	11 years, 6 months
28	341-Palomar	14.82	30 years	3.29	3.81	SQ	15 years, 6 months
29	341-Solar	0.072	25 years		4	SQ	0 years
30	342-CPEP	0.627	25 years	5.02	7.65	SQ	6 years, 6 months
31	342-Desert Star	0.878	30 years	24.16	11.85	SQ	5 years, 3 months, 18 days
32	342-Miramar	5.233	25 years	2.92	4.51	SQ	11 years, 6 months
33	342-Palomar	14.914	30 years	1.45	3.7	SQ	15 years, 6 months
34	343-CPEP	16.859	25 years		8.09	SQ	6 years, 6 months
35	343-Desert Star	24.382	30 years		6.07	SQ	5 years, 3 months, 18 days
36	343-Miramar	53.287	25 years		4.16	SQ	11 years, 6 months
37	343-Palomar		30 years			SQ	15 years, 6 months
38	344-CPEP	6.096	25 years	9.07	13.31	SQ	6 years, 6 months
39	344-Desert Star	108.731	30 years	0.42	5.28	SQ	5 years, 3 months, 18 days
40	344-Miramar	19.736	25 years	2.61	4.98	SQ	11 years, 6 months
41	344-Palomar	156.883	30 years	0.6	3.39	SQ	15 years, 6 months
42	344-Solar	58.683	25 years		4.07	SQ	17 years, 4 months, 24 days
43	344-Wind	1.767	20 years		5.03	SQ	12 years, 6 months
44	345-CPEP	0.834	25 years	14.47	8.54	SQ	6 years, 6 months
45	345-Desert Star	9.572	30 years	4.71	5.32	SQ	5 years, 3 months, 18 days
46	345-Miramar	13.461	25 years	1.08	4.25	SQ	11 years, 6 months
47	345-Palomar	6.706	30 years	3.06	3.28	SQ	15 years, 6 months
48	345-Solar	2.332	25 years		4	SQ	12 years, 7 months, 6 days
49	345-Wind		20 years		5	SQ	0 years
50	346-CPEP	5.071	25 years		11.25	SQ	6 years, 6 months
51	346-Desert Star	22.374	30 years		5.14	SQ	5 years, 3 months, 18 days
52	346-Miramar	11.908	25 years		7.18	SQ	11 years, 6 months
53	346-Palomar	19.644	30 years		6.16	SQ	15 years, 6 months
54	SUBTOTAL	584.847
55	TRANSMISSION-SWPL
56	352	40.83	74 years	75	2.18	R2.5	54 years, 7 months, 6 days
57	353	327.314	50 years	70	3.49	R1.5	40 years, 7 months, 6 days
58	354	62.029	70 years	75	2.02	R5	36 years, 6 months
59	355	10.306	45 years	100	3.4	R1.5	25 years, 6 months
60	356	46.685	64 years	100	1.42	R2	38 years, 4 months, 24 days
61	359	5.324	60 years		1.51	SQ	31 years, 7 months, 6 days
62	SUBTOTAL	492.488
63	TRANSMISSION-SRPL
64	352	124.028	74 years	75	2.41	R2.5	68 years, 9 months, 18 days
65	353	164.627	50 years	70	3.48	R1.5	45 years, 7 months, 6 days
66	354	766.912	70 years	75	2.57	R5	64 years, 6 months
67	355	3.344	45 years	100	4.51	R1.5	40 years, 6 months
68	356	173.454	64 years	100	3.22	R2	58 years, 9 months, 18 days
69	357	80.523	60 years	30	2.2	R5	54 years, 6 months
70	358	126.452	50 years	10	2.19	R2	45 years, 1 month, 6 days
71	359	241.126	60 years		1.66	SQ	54 years, 6 months
72	SUBTOTAL	1,680.466
73	TRANSMISSION-OTHER
74	352	532.127	74 years	75	2.37	R2.5	67 years, 10 months, 24 days
75	353	1,565.85	50 years	70	3.49	R1.5	43 years, 6 months
76	353.4	1.42	50 years	70	3.64	R1.5	40 years, 1 month, 6 days
77	354	96.717	70 years	75	2.36	R5	48 years, 10 months, 24 days
78	355	933.766	45 years	100	4.57	R1.5	39 years, 9 months, 18 days
79	356	619.36	64 years	100	3.03	R2	53 years, 9 months, 18 days
80	357	474.566	60 years	30	2.14	R5	52 years
81	358	439.061	50 years	10	2.13	R2	43 years, 6 months
82	359	123.913	60 years		1.69	SQ	52 years, 9 months, 18 days
83	SUBTOTAL	4,786.78
84	DISTRIBUTION
85	361	12.899	63 years	125	3.77	R2.5	54 years, 10 months, 24 days
86	362.1	641.548	51 years	125	4.62	R1.5	39 years, 9 months, 18 days
87	363	155.273	10 years		9.85	SQ	5 years, 9 months, 18 days
88	364	976.408	47 years	100	4.21	R0.5	39 years, 9 months, 18 days
89	365	1,049.006	55 years	70	2.98	R0.5	48 years, 4 months, 24 days
90	366	1,636.908	57 years	50	2.65	R3	43 years, 1 month, 6 days
91	367	1,884.43	45 years	65	3.52	R3	30 years, 9 months, 18 days
92	368.1	742.302	34 years	70	5.22	L0.5	26 years, 1 month, 6 days
93	368.2	33.857	12 years	70	16.36	L0	7 years, 9 months, 18 days
94	369.1	257.03	55 years	110	3.44	R0.5	47 years, 3 months, 18 days
95	369.2	398.29	53 years	75	3.08	L4	34 years, 1 month, 6 days
96	370.1	7.701	48 years		2.08	R0.5	44 years, 7 months, 6 days
97	370.11	202.551	15 years		6.65	SQ	5 years, 3 months, 18 days
98	E370.20	9.376	48 years		2.18	R0.5	45 years, 1 month, 6 days
99	E370.21	61.203	15 years		6.71	SQ	6 years, 3 months, 18 days
100	E371.00	10.172	34 years	90	3.58	R0.5	22 years, 6 months
101	E371.1	64.419	10 years		11.02	SQ	0 years
102	E373.20	34.753	36 years	85	4.51	L0	26 years, 2 months, 12 days
103	SUBTOTAL	8,178.126
104	GENERAL
105	390	45.467	34 years	10	2.59	S4	18 years, 7 months, 6 days
106	392.2	0.058	27 years		4.38	L5	13 years, 6 months
107	393.1	0.046	25 years		4.01	S5	22 years, 6 months
108	394.11	39.354	27 years		3.73	S6	18 years, 4 months, 24 days
109	394.2	0.278	26 years		2.76	L4	6 years, 8 months, 12 days
110	395.1	5.336	22 years		4.6	L3	15 years, 10 months, 24 days
111	397.1	373.821	30 years	50	4.9	R2	22 years, 6 months
112	397.2	8.197	30 years	50	4.47	R2	19 years
113	397.6	14.164	30 years		3.16	R2	22 years, 8 months, 12 days
114	397.7	2.2	30 years	50	5.13	R2	28 years, 3 months, 18 days
115	398.1	3.242	16 years		6.31	L4	9 years, 7 months, 6 days
116	SUBTOTAL	492.163
117	TOTAL	16,752.432

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: DepreciationAndAmortization

Reclassification of 2021 Electric Depreciation and Amortization Charges Depreciation and Amortization Expense Charged in Accordance with FERC Seven Factor Test In Accordance with Guidelines in FERC Order 888


	Depreciation Expense (Account 403)	Amortization of Limited Term Electric Plant (Account 404)	Amortization of Other Electric Plant (Account 405)	Total

Intangible Plant	—	15,043,789	—	15,043,789
Steam Production	25,682,223	—	—	25,682,223
Nuclear Production	—	—	—	—
Other Production	26,108,598	—	—	26,108,598
Transmission Plant	207,188,991	—	1,938,548	209,127,539
Distribution Plant	321,795,786	—	2,078,582	323,874,368
General Plant	22,351,710	—	—	22,351,710
Common Plant-Electric	56,368,616	67,509,038	—	123,877,654
Total Ratemaking Electric Depreciation & Amort. (1)	659,495,924	82,552,827	4,017,130	746,065,881

(1) Ties to Line 12 of FERC Form 1, page 336

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

REGULATORY COMMISSION EXPENSES
Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	D. 20-12-039 ENERGY STORAGE PROCUREMENT		2,693.22	2,693.22		Elec	928	2,693
2	D. 20-12-041 ELECTRICITY INTEGRATED RESOURCE		999.45	999.45		Elec	928	999
3	D. 20-12-042 RESIDENTIAL RATE DESIGN WINDOW		4,221.46	4,221.46		Elec	928	4,221
4	D. 20-12-043 RESIDENTIAL RATE DESIGN WINDOW		7,928.99	7,928.99		Elec	928	7,929
5	D. 21-02-016 INTEGRATED DISTRIBUTED ENERGY		2,484.48	2,484.48		Elec	928	2,484
6	D. 21-02-017 RESIDENTIAL RATE DESIGN WINDOW		15,406.44	15,406.44		Elec	928	15,406
7	D. 21-02-018 ENERGY EFFICIENCY ROLLING PORTFOLIO_1		483.18	483.18		Elec	928	483
8	D. 21-02-018 ENERGY EFFICIENCY ROLLING PORTFOLIO_2		55.92	55.92		Gas	928	56
9	D. 21-02-019 PIPELINE SAFETY AND RELIABILITY PROJECT		1,809.24	1,809.24		Gas	928	1,809
10	D. 21-02-020 BUILDING DECARBONIZATION_1		3,442.16	3,442.16		Elec	928	3,442
11	D. 21-02-020 BUILDING DECARBONIZATION_2		510.24	510.24		Gas	928	510
12	D. 21-02-021 BUILDING DECARBONIZATION _1		5,980.20	5,980.20		Elec	928	5,980
13	D. 21-02-021 BUILDING DECARBONIZATION_2		886.47	886.47		Gas	928	886
14	D. 21-02-022 BUILDING DECARBONIZATION_1		1,825.35	1,825.35		Elec	928	1,825
15	D. 21-02-022 BUILDING DECARBONIZATION_2		270.58	270.58		Gas	928	271
16	D. 21-02-023 BUILDING DECARBONIZATION _1		4,018.42	4,018.42		Elec	928	4,018
17	D. 21-02-023 BUILDING DECARBONIZATION_2		595.67	595.67		Gas	928	596
18	D. 21-02-024 BUILDING DECARBONIZATION_1		3,297.87	3,297.87		Elec	928	3,298
19	D. 21-02-024 BUILDING DECARBONIZATION_2		488.85	488.85		Gas	928	489
20	D. 21-02-025 BUILDING DECARBONIZATION_1		3,495.60	3,495.60		Elec	928	3,496
21	D. 21-02-025 BUILDING DECARBONIZATION_2		518.16	518.16		Gas	928	518
22	D. 21-02-026 ELECTRICITY INTEGRATED RESOURCE		18,866.47	18,866.47		Elec	928	18,866
23	D. 21-02-027 WILDFIRE EXPENSE		14,685.61	14,685.61		Elec	928	14,686
24	D. 21-03-011 MOBILEHOME PARK PILOT PROGRAM_1		461.22	461.22		Elec	928	461
25	D. 21-03-011 MOBILEHOME PARK PILOT PROGRAM_2		53.38	53.38		Gas	928	53
26	D. 21-03-012 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_1		1,371.09	1,371.09		Elec	928	1,371
27	D. 21-03-012 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_2		203.25	203.25		Gas	928	203
28	D. 21-03-015 RESIDENTIAL RATE STRUCTURES		3,113.73	3,113.73		Elec	928	3,114
29	D. 21-03-016 RESIDENTIAL RATE STRUCTURES		2,666.43	2,666.43		Elec	928	2,666
30	D. 21-03-031 ELECTRICITY INTEGRATED RESOURCE		1,431.24	1,431.24		Elec	928	1,431
31	D. 21-03-032 ENERGY EFFICIENCY ROLLING PORTFOLIO_1		5,446.76	5,446.76		Elec	928	5,447
32	D. 21-03-032 ENERGY EFFICIENCY ROLLING PORTFOLIO_2		807.39	807.39		Gas	928	807
33	D. 21-03-034 ELECTRICITY INTEGRATED RESOURCE		3,546.49	3,546.49		Elec	928	3,546
34	D. 21-03-036 ELECTRICITY INTEGRATED RESOURCE		6,770.40	6,770.40		Elec	928	6,770
35	D. 21-03-037 ELECTRICITY INTEGRATED RESOURCE		7,109.49	7,109.49		Elec	928	7,110
36	D. 21-03-038 ELECTRICITY INTEGRATED RESOURCE		3,991.87	3,991.87		Elec	928	3,992
37	D. 21-03-039 ELECTRICITY INTEGRATED RESOURCE		24,544.22	24,544.22		Elec	928	24,544
38	D. 21-03-040 ELECTRICITY INTEGRATED RESOURCE		21,114.52	21,114.52		Elec	928	21,115
39	D. 21-03-053 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_1		108.43	108.43		Elec	928	108
40	D. 21-03-053 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_2		12.55	12.55		Gas	928	13
41	D. 21-04-009 WILDFIRE MITIGATION PLANS		1,108.03	1,108.03		Elec	928	1,108
42	D. 21-04-011 WILDFIRE MITIGATION PLANS		3,905.90	3,905.90		Elec	928	3,906
43	D. 21-04-012 RESIDENTIAL RATE STRUCTURES		24,028.51	24,028.51		Elec	928	24,029
44	D. 21-05-010 PUBLIC UTILITY REGULATORY POLICIES		1,986.00	1,986.00		Elec	928	1,986
45	D. 21-05-011 WILDFIRE MITIGATION PLANS		8,378.59	8,378.59		Elec	928	8,379
46	D. 21-05-013 WILDFIRE MITIGATION PLANS		6,381.18	6,381.18		Elec	928	6,381
47	D. 21-05-014 MOBILEHOME PARK PILOT PROGRAM_1		11,841.99	11,841.99		Elec	928	11,842
48	D. 21-05-014 MOBILEHOME PARK PILOT PROGRAM_2		1,370.45	1,370.45		Gas	928	1,371
49	D. 21-05-025 POWER CHARGE INDIFFERENCE		6,658.84	6,658.84		Elec	928	6,659
50	D. 21-05-026 ELECTRICITY INTEGRATED RESOURCE		1,610.73	1,610.73		Elec	928	1,611
51	D. 21-05-027 DISTRIBUTION RESOURCES PLANS		28,737.98	28,737.98		Elec	928	28,738
52	D. 21-05-028 RESIDENTIAL RATE DESIGN WINDOW		9,743.61	9,743.61		Elec	928	9,744
53	D. 21-05-029 WILDFIRE MITIGATION PLANS		67,865.23	67,865.23		Elec	928	67,865
54	D. 21-06-010 CALIFORNIA DISTRIBUTED GENERATION STATISTICS		1,737.50	1,737.50		Elec	928	1,738
55	D. 21-06-011 WILDFIRE MITIGATION PLANS		2,727.66	2,727.66		Elec	928	2,728
56	D. 21-07-022 ENERGY ACCESS_1		9,635.65	9,635.65		Elec	928	9,636
57	D. 21-07-022 ENERGY ACCESS_2		1,428.32	1,428.32		Gas	928	1,428
58	D. 21-07-024 ENERGY ACCESS_1		8,064.48	8,064.48		Elec	928	8,065
59	D. 21-07-024 ENERGY ACCESS_2		1,195.42	1,195.42		Gas	928	1,195
60	D. 21-07-025 ENERGY ACCESS_1		10,767.39	10,767.39		Elec	928	10,767
61	D. 21-07-025 ENERGY ACCESS_2		1,596.08	1,596.08		Gas	928	1,596
62	D. 21-07-026 DE-ENERGIZATION POWER LINES		9,941.98	9,941.98		Elec	928	9,942
63	D. 21-08-013 PUBLIC UTILITY REGULATORY POLICIES		10,242.03	10,242.03		Elec	928	10,242
64	D. 21-08-014 DE-ENERGIZATION POWER LINES		1,046.03	1,046.03		Elec	928	1,046
65	D. 21-08-015 AFFORABLE UTILITY SERVICE_1		7,408.78	7,408.78		Elec	928	7,409
66	D. 21-08-015 AFFORABLE UTILITY SERVICE_2		1,098.23	1,098.23		Gas	928	1,098
67	D. 21-08-016 DE-ENERGIZATION POWER LINES		3,387.58	3,387.58		Elec	928	3,388
68	D. 21-08-017 DE-ENERGIZATION POWER LINES		6,396.39	6,396.39		Elec	928	6,396
69	D. 21-08-018 DE-ENERGIZATION POWER LINES		3,139.97	3,139.97		Elec	928	3,140
70	D. 21-08-030 RESOURCE ADEQUACY PROGRAM		9,737.92	9,737.92		Elec	928	9,738
71	D. 21-08-031 DE-ENERGIZATION POWER LINES		7,415.28	7,415.28		Elec	928	7,415
72	D. 21-08-033 ENERGY ACCESS_1		14,739.12	14,739.12		Elec	928	14,739
73	D. 21-08-033 ENERGY ACCESS_2		1,705.73	1,705.73		Gas	928	1,706
74	D. 21-08-035 MICROGRIDS		4,811.87	4,811.87		Elec	928	4,812
75	D. 21-09-014 RESIDENTIAL RATES		26,805.85	26,805.85		Elec	928	26,806
76	D. 21-09-033 CLIMATE CHANGE ADAPTATION_1		8,565.30	8,565.30		Elec	928	8,565
77	D. 21-09-033 CLIMATE CHANGE ADAPTATION_2		991.25	991.25		Gas	928	991
78	D. 21-09-036 ELECTRIC SALES FORECAST		18,971.64	18,971.64		Elec	928	18,972
79	D. 21-10-007 NATURAL GAS PIPELINES		13,390.19	13,390.19		Gas	928	13,390
80	D. 21-10-008 WILDFIRE MITIGATION PLANS		6,781.49	6,781.49		Elec	928	6,782
81	D. 21-10-011 TRIENNIAL COST ALLOCATION		2,344.59	2,344.59		Gas	928	2,345
82	D. 21-10-028 RESOURCE ADEQUACY PROGRAM		20,845.54	20,845.54		Elec	928	20,846
83	D. 21-11-022 RESOURCE ADEQUACY PROGRAM		2,119.50	2,119.50		Elec	928	2,120
84	D. 21-11-023 RESOURCE ADEQUACY PROGRAM		14,183.55	14,183.55		Elec	928	14,184
85	D. 21-11-024 INTEGRATED DISTRIBUTED ENERGY RESOURCES		23,819.65	23,819.65		Elec	928	23,820
86	D. 21-11-025 ELECTRICITY INTEGRATED RESOURCE		10,081.07	10,081.07		Elec	928	10,081
87	D. 21-11-026 COST OF CAPITAL_1		15,140.26	15,140.26		Elec	928	15,140
88	D. 21-11-026 COST OF CAPITAL_2		2,244.29	2,244.29		Gas	928	2,244
89	D. 21-11-027 TRIENNIAL COST ALLOCATION		1,455.29	1,455.29		Gas	928	1,455
90	D. 21-12-012 WILDFIRE MITIGATION PLANS		5,139.46	5,139.46		Elec	928	5,140
91	D. 21-12-014 ELECTRICITY INTEGRATED RESOURCE		5,939.03	5,939.03		Elec	928	5,939
92	California Public Utilities Commission fees_1	22,235,548.60		22,235,548.60		Elec	928	22,235,549
93	California Public Utilities Commission fees_2	3,646,904.50		3,646,904.50		Gas	928	3,646,905
94	FERC Proceedings _1		270,233.87	270,233.87		Elec	928	270,234
95	FERC Proceedings_2		91,670.33	91,670.33		Gas	928	91,670
96	Miscellaneous_1		12,256,696.47	12,256,696.47		Elec	928	12,256,696
97	Miscellaneous_2		3,567,536.31	3,567,536.31		Gas	928	3,567,536
98	D. 20-01-016 DISTRIBUTED ENERGY & RULE 21		3,832.27	3,832.27		Elec	928	3,832
46	TOTAL	25,882,453.10	16,838,344.14	42,720,797.24				42,720,797

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e). Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	A. Electric R, D & D Performed Internally
2	(1) Generation	NONE
3	(2) System Planning, Engineering and Operation	NONE
4	(3) Transmission	NONE
5	(4) Distribution	RD&D Performed Internally	4,996,641		588	4,996,641
6			35,314		408	35,314
7	(5) Environment	NONE
8	(6) Other	NONE
9	(7) Sub Total Internal Costs Incurred		5,031,955			5,031,955
10	B. External
11	(1) Research Support to the Electrical	NONE
12	Research Council or the Electrical Power	NONE
13	Research Institute	NONE
14	(2) Research Support to Edison Electric Inst.	NONE
15	(3) Research Support to Nuclear Power Groups	NONE
16	(4) Research Support to Others	CPUC and California Energy Commission		18,822,643	588	18,822,643
17	(5) Sub Total External Costs Incurred			18,822,643		18,822,643

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.
Line No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	10,228,064
4	SalariesAndWagesElectricOperationTransmission Transmission	15,537,615
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	45,868,701
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	17,729,049
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	17,269,345
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	52,377,243
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	159,010,017
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	2,123,124
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	13,157,040
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	19,930,291
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	1,459,234
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	36,669,689
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	12,351,188
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	28,694,655
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	65,798,992
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	17,729,049
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	17,269,345
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	53,836,477
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	195,679,706	48,262,727	243,942,433
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing	168,162
35	SalariesAndWagesGasOperationTransmission Transmission	2,828,984
36	SalariesAndWagesGasOperationDistribution Distribution	29,075,577
37	SalariesAndWagesGasCustomerAccounts Customer Accounts	8,758,536
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational	2,203,151
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General	17,076,523
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)	60,110,933
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission	1,207,516
48	SalariesAndWagesGasMaintenanceDistribution Distribution	7,762,257
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General	579,316
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)	9,549,089
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru	168,162
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)	4,036,500
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)	36,837,834
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)	8,758,536
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)	2,203,151
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)	17,655,839
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)	69,660,022	16,647,370	86,307,392
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	265,339,728	64,910,097	330,249,825
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	84,994,108	154,554,801	239,548,909
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant	21,622,166	34,994,705	56,616,871
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	106,616,274	189,549,506	296,165,780
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	7,619,504	13,782,759	21,402,263
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant	1,463,390	1,503,610	2,967,000
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	9,082,894	15,286,369	24,369,263
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 3rd Party Billings, Gas	1,579,775	898,658	2,478,433
80	SalariesAndWagesOtherAccountsDescription 3rd Party Billings, Electric	5,098,018	2,942,800	8,040,818
81	SalariesAndWagesOtherAccountsDescription Affiliate Billings, Gas		10,299,792	10,299,792
82	SalariesAndWagesOtherAccountsDescription Affiliate Billings, Electric		30,362,631	30,362,631
83	SalariesAndWagesOtherAccountsDescription
84	SalariesAndWagesOtherAccountsDescription
85	SalariesAndWagesOtherAccountsDescription
86	SalariesAndWagesOtherAccountsDescription
87	SalariesAndWagesOtherAccountsDescription
88	SalariesAndWagesOtherAccountsDescription
89	SalariesAndWagesOtherAccountsDescription
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	6,677,793	44,503,881	51,181,674
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	387,716,689	314,249,853	(a) 701,966,542

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: SalariesAndWagesGeneralExpense

FERC accounts 417 and 426 are not included in the detail classification lines or summary totals.

FERC 417 for 2021 amounts to $3,110,104

FERC 426 for 2021 amounts to $1,280,345

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

COMMON UTILITY PLANT AND EXPENSES

Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.


Account	Balance Beg. of Year	Additions	Retire From Serv.	Adjs.	Transfers	Balance End of Year

303 Misc. Intangible Plant	685,051,572	345,014,337	124,598,184	(160,597)		905,307,128
389 Land & Land Rights	7,522,569			4		7,522,573
390 Structures & Improvs.	508,494,134	54,341,094		(269,669)	118,133	562,683,692
391 Office Furn. & Equip.	146,758,601	28,108,325	11,716,842	(52,005)		163,098,079
392 Transportation Equip.	12,515,872	137,812		(166)		12,653,518
393 Stores Equipment	333,836			(853)		332,983
394 Tools, Shop & Garage Eq.	3,501,263		636	(24)		3,500,603
395 Laboratory Equipment	1,731,117			(22)		1,731,095
396 Power Equipment	0					0
397 Communication Eq.	306,074,404	57,023,426	9,144,218	(76,418)		353,877,194
398 Misc. Equipment	3,587,315	343		(2,595)		3,585,063

FIN 47 ARC-Common	7,167,302			(1,661,903)		5,505,399
Fleet Capital Leases	91,311,488	22,054,277	2,880,443			110,485,322
Other Capital Leases	118,014,626	8,396,037				126,410,663

TOTAL COMMON PLANT	1,892,064,099	515,075,651	148,340,323	(2,224,248)	118,133	2,256,693,312
Construction Work in Prog.	418,262,973	(60,924,537)				357,338,436

TOTAL COMMON PLANT	2,310,327,072	454,151,114	148,340,323	(2,224,248)	118,133	2,614,031,748


			December 31, 2021
ACCOUNT			Accumulated Depreciation

303 Misc. Intangible Plant			449,430,696
389 Land & Land Rights			27,776
390 Structures and Improvements			195,013,888
391 Office Furniture & Equipment			74,918,490
392 Transportation Equipment			4,940,975
393 Stores Equipment			72,500
394 Tools, Shop, & Garage Equipment			1,449,949
395 Laboratory Equipment			1,017,411
396 Power Operated Equipment			(192,979)
397 Communication Equipment			130,419,384
398 Miscellaneous Equipment			833,853
108.4 Retirement Work in Progress			0
FIN 47 Accumulated Depreciation			2,922,489
Fleet Capital Lease			44,534,499
Other Capital Lease			56,569,524

Total Accumulated Depreciation			961,958,455


Split of Common Utility Plant to Departments: (excluding CWIP)			December 31, 2021

			Balance End of Year	Accumulated Depreciation
Electric	74.67	%	1,685,072,898	718,294,379
Gas	25.33	%	571,620,417	243,664,077

TOTAL	100.00	%	2,256,693,315	961,958,456


	Ad Valorem Taxes	Depreciation

	Note (1)	Note (2)
ACCOUNT

303 Misc. Intangible Plant		90,409,855
389 Land and Land Rights		—
390 Structures & Improvements		19,146,506
391 Office Furniture & Equipment		29,293,321
392 Transportation Equipment		1,176,142
393 Stores Equipment		16,487
394 Portable Tools		182,263
395 Laboratory Equipment		76,165
396 Power Operated Equipment		—
397 Communication Equipment		25,361,203
398 Miscellaneous Equipment		238,225

TOTAL		165,900,167

(1)Ad Valorem Taxes on property are assessed by the State Board of Equalization and consist of one-half of the taxes from each fiscal tax year 2020-2021 and 2021-2022. Ad Valorem Taxes are assessed on the entire operating unit, therefore, assessed taxes are not available by account number. Ad Valorem Taxes are allocated based on procedures adopted by the California Public Utilities Commission.

(2)The Common Utility Plant and Accumulated Depreciation is allocated between the Electric and Gas Departments based on labor ratios in accordance with allocation procedures adopted by the California Public Utilities Commission. These rates were revised in January 2021.

Other expenses of operation, maintenance and rents for common utility plant are allocated based on labor percentage studies. Specific amounts charged to operations and maintenance are not readily available.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)	144,278,874	279,336,249	527,201,265	706,304,175
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)	70,625,074	139,830,057	374,148,439	501,451,465
4	Transmission Rights
5	Ancillary Services	953,348	1,791,408	1,968,125	1,341,092
6	Other Items (list separately)
7	Congestion	1,840,959	3,531,344	6,671,971	7,236,270
8	CRR (Congestion Revenue Rights)	4,741,526	8,396,144	12,897,017	19,285,963
9	GMC (Grid Management Charges)	1,572,767	3,547,137	5,873,902	7,571,934
10	Other	1,034,948	56,723	1,080,822	135,928
11	UFE (Unaccounted for Energy)	3,101,454	682,735	1,413,415	6,607,198
46	TOTAL	75,345,854	140,605,949	154,337,214	195,244,773

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
		Amount Purchased for the Year			Amount Sold for the Year
		Usage - Related Billing Determinant			Usage - Related Billing Determinant
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch	1,339,669	MWH	10,318,211	1,502,316	MWH	8,977,120
2	Reactive Supply and Voltage
3	Regulation and Frequency Response
4	Energy Imbalance
5	Operating Reserve - Spinning
6	Operating Reserve - Supplement
7	Other
8	Total (Lines 1 thru 7)	1,339,669		10,318,211	1,502,316		8,977,120

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	3,065	25	18	3,065
2	February	2,792	9	18	2,792
3	March	2,861	3	18	2,861
4	Total for Quarter 1				8,718	0	0			0
5	April	2,828	30	17	2,828
6	May	2,730	25	18	2,730
7	June	3,524	15	17	3,524
8	Total for Quarter 2				9,082	0	0			0
9	July	3,519	20	17	3,519
10	August	3,860	26	16	3,860
11	September	3,826	9	16	3,826
12	Total for Quarter 3				11,205	0	0			0
13	October	3,178	3	17	3,178
14	November	3,075	12	16	3,075
15	December	3,112	16	18	3,112
16	Total for Quarter 4				9,365	0	0			0
17	Total				38,370	0	0	0	0	0

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Monthly ISO/RTO Transmission System Peak Load
Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

2022-04-15

Year/Period of Report

End of:

2021

/

Q4

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	11,298,500
3	Steam	2,835,684	23	Requirements Sales for Resale (See instruction 4, page 311.)
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	9,195,146
5	Hydro-Conventional		25	Energy Furnished Without Charge
6	Hydro-Pumped Storage	47,969	26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)	59,413
7	Other	20,137	27	Total Energy Losses	354,640
8	Less Energy for Pumping	62,165	27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	2,841,625	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	20,907,699
10	Purchases (other than for Energy Storage)	18,066,074
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	1,192,312
13	Delivered	1,192,312
14	Net Exchanges (Line 12 minus line 13)	0
15	Transmission For Other (Wheeling)
16	Received
17	Delivered
18	Net Transmission for Other (Line 16 minus line 17)	0
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	20,907,699

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

MONTHLY PEAKS AND OUTPUT
Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	1,190,990	416,403	3,065	25	18
30	February	1,093,087	503,003	2,792	9	18
31	March	1,005,091	654,770	2,861	3	18
32	April	888,357	760,224	2,828	30	17
33	May	915,669	666,242	2,730	25	18
34	June	1,029,334	797,466	3,524	15	17
35	July	894,407	906,929	3,519	20	17
36	August	889,647	1,472,270	3,860	26	16
37	September	1,005,458	893,348	3,826	9	16
38	October	793,474	669,977	3,178	3	17
39	November	764,564	691,374	3,075	12	16
40	December	828,422	763,140	3,112	16	18
41	Total	11,298,500	9,195,146

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.	Item (a)	Plant Name: Cuyamaca	Plant Name: Desert Star	Plant Name: Miramar	Plant Name: Palomar
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)	Gas Turbine	Combined Cycle	Gas Turbine (2)	Combined Cycle
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)	Semi-Outdoor	Semi-Outdoor	Semi-Outdoor	Semi-Outdoor
3	YearPlantOriginallyConstructed Year Originally Constructed	2002	2000	2005	2006
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed	2002	2000	2009	2006
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)	47	536	96	588
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)	47	485	96	588
7	PlantHoursConnectedToLoad Plant Hours Connected to Load	481	8,760	435	4,815
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)	47	450	96	588
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water	47	450	96	588
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water	47	450	96	0
11	PlantAverageNumberOfEmployees Average Number of Employees	1	23	3	32
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh	8,182,000	1,000,359,308	20,180,000	1,833,691,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights				14,480,000
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements	1,897,458	32,654,564	5,075,863	79,334,067
15	CostOfEquipmentSteamProduction Equipment Costs	30,500,752	314,306,477	106,413,303	518,543,801
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		1,955,311
17	CostOfPlant Total cost (total 13 thru 20)	32,398,210	348,916,352	111,489,166	612,357,868
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including	689.3236	650.9633	1,161.3455	1,041.4249
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr	1,750	719,844	4,073	1,454,949
20	FuelSteamPowerGeneration Fuel	894,996	44,258,740	1,488,814	95,242,721
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)
22	SteamExpensesSteamPowerGeneration Steam Expenses	7,494	2,112,465	6,999	4,103,433
23	SteamFromOtherSources Steam From Other Sources
24	SteamTransferredCredit Steam Transferred (Cr)				934
25	ElectricExpensesSteamPowerGeneration Electric Expenses	278,410	1,381,502	291,783	2,757,396
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses
27	RentsSteamPowerGeneration Rents				306
28	Allowances Allowances
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures	13,158			82,914
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		2,282,573		795,759
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant	921,377	7,468,600	1,852,599	5,314,835
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant	751	1,180,570	2,749	6,601,633
34	PowerProductionExpensesSteamPower Total Production Expenses	2,117,936	59,404,294	3,647,017	116,189,052
35	ExpensesPerNetKilowattHour Expenses per Net kWh	0.2589	0.0593	0.1807	0.0634

35	FuelKindAxis Plant Name	Cuyamaca	Desert Star	Miramar	Palomar
36	FuelKind Fuel Kind	GAS	GAS	GAS	GAS
37	FuelUnit Fuel Unit	Mcf	Mcf	Mcf	Mcf
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	92,315	7,407,765	201,966	12,700,404
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)			0	0
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	9.695	5.975	7.372	7.499
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	9.486	5.846	7.213	7.338
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.109	0.045	0.074	0.052
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	11,587.000	7,657.000	10,278.000	7,113.000

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantKind Kind of Plant (Run-of-River or Storage)
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)
3	YearPlantOriginallyConstructed Year Originally Constructed
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)
7	PlantHoursConnectedToLoad Plant Hours Connect to Load
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways
17	EquipmentCostsHydroelectricProduction Equipment Costs
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs
20	CostOfPlant Total cost (total 13 thru 20)
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering
24	WaterForPower Water for Power
25	HydraulicExpenses Hydraulic Expenses
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses
28	RentsHydraulicPowerGeneration Rents
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)
35	ExpensesPerNetKilowattHour Expenses per net kWh

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. If net peak demand for 60 minutes is not available, give that which is available, specifying period. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)
2	YearPlantOriginallyConstructed Year Originally Constructed
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	0
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0
8	PlantAverageNumberOfEmployees Average Number of Employees
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0
10	EnergyUsedForPumping Energy Used for Pumping
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0
21	CostOfPlant Total cost (total 13 thru 20)
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)
36	PumpingExpenses Pumping Expenses
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))	0

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

GENERATING PLANT STATISTICS (Small Plants)

Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating).
Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.
List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.
If net peak demand for 60 minutes is not available, give the which is available, specifying period.
If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Production Expenses

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

1

J&D Labs Fuel Cell

2012

0.40

3,305,506

7,505,525

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINE STATISTICS
Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g). Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	Miguel	East County	500	500	1S,3	54.00		1	2-2156 ACSR
2	Imperial Valley	North Gila	500	500	1S,3	(a) 79.00		1	2-2156 ACSR
3	North Gila	Palo Verde	500	500	3	(b) 114.00		1	2-2156 ACSR
4	Suncrest	Ocotillo Switchyard	500	500	3	(c) 67.00		1	3-1033.5 ACSR
5	East County	Imperial Valley	500	500	1S,3	31.00		1	2-2156 ACSR
6	Octillo Switchyard	Imperial Valley	500	500	3	22.00	13	1	3-1033.5 ACSR
7	Octillo Switchyard	Ocotillo Express Sub	500	500	3	0.00		1	2-1590 ACSR
8	San Luis Rey	Mission	230	230	3,1S		30	2	1-1033.5 ACSR/AW
9			230	230	2W	4.26		1	1-1033.5 ACSR/AW
10		Mission	230	230	4		0	2	1-5000 KCMIL CU ENAMEL
11	San Onofre		230	230	2S		0	5	2-1033.5 ACSR/AW
12	_1		230	230	2S,3		17	2	2-1033.5 ACSR/AW
13		San Luis Rey	230	230	1S,2W	0.75		1	2-1033.5 ACSR/AW
14	San Luis Rey		230	230	1S,3		6	2	2-1033.5 ACSR/AW
15		Encina	230	230	1S,3		1	2	2-1109 ACAR
16	San Luis Rey	San Luis Rey	230	230	2W	4.26		1	1-1033.5 ACSR/AW
17	_2		230	230	1S,3		30	2	1-1033.5 ACSR/AW
18		Mission_2	230	230	4		0	2	1-5000 KCMIL CU ENAMEL
19	San Luis Rey		230	230	1S,2W,3S,3	17.61		1	1-1033.5 ACSR/AW
20			230	230	1S		0	2	1-1033.5 ACSR/AW
21		San Onofre	230	230	2S		0	5	2-1033.5 ACSR/AW
22	San Onofre_1		230	230	1S,3		6	2	1-1033.5 ACSR/AW
23			230	230	2S,3		1	5	2-1033.5 ACSR/AW
24		Talega	230	230	3	0.11		1	2-1033.5 ACSR/AW
25	San Onofre_2		230	230	2W,2S	1.00		1	2-1033.5 ACSR/AW
26			230	230	2S		0	5	2-1033.5 ACSR/AW
27		San Luis Rey	230	230	2S,3		17	2	2-1033.5 ACSR/AW
28	San Luis Rey_2		230	230	1S,3		6	2	2-1033.5 ACSR/AW
29	_1		230	230	1S,3		2	2	2-1109 ACAR
30			230	230	3		7	2	2-1109 ACAR
31			230	230	1S		5	2	2-1109 ACAR
32			230	230	1S		1	2	2-900 ACSS/AW
33		Palomar Energy	230	230	1S	0.26		1	2-1109 ACAR
34	Encina		230	230	1S,3		18	2	2-1109 ACAR
35		Penasquitos	230	230	1S		0	2	2-1033.5 ACSR/AW
36	Penasquitos		230	230	1S		2	2	2-1033.5 ACSR/AW
37		Old Town	230	230	1S	7.19		1	2-1109 ACAR
38	Palomar_1		230	230	1S		0	2	2-900 ACSS/AW
39		Old Town	230	230	1S		0	2	2-605 ACSS/AW
40	Palomar_2		230	230	1S		0	2	2-900 ACSS/AW
41		Old Town_1	230	230	1S		0	2	2-605 ACSS/AW
42	East County	Eco Gen 1	230	230	1S		0	2	2-1113 ACSS/AW
43	Miguel	Bay Blvd	230	230	2S		10	2	2-900 ACSS/AW
44	Miguel_1		230	230	1S,3		23	2	2-1033.5 ACSR/AW
45	_4		230	230	3		1	2	2-605 ACSS/AW
46		Sycamore Canyon	230	230	1S,3		4	2	2-900 ACSS/AW
47	Miguel		230	230	1S,3		9	2	2-605 ACSS/AW
48			230	230	1S,3		15	2	2-636 ACSS/AW
49			230	230	1S		1	2	2-1033.5 ACSR/AW
50	_3		230	230	1S,3		1	2	2-1109 ACAR
51		Mission	230	230	1S		8	2	1-1109 ACAR
52	Miguel		230	230	1S		9	2	2-605 ACSS/AW
53			230	230	1S		1	2	2-1109 ACAR
54			230	230	1S,3		9	2	2-1033.5 ACSR/AW
55		Mission	230	230	1S,3		15	2	2-636 ACSS/AW
56	Bay Boulavard		230	230	4	2.83		1	2-3500 KCMIL CU
57			230	230	4	1.00		1	2-4000 KCMIL CU
58		Silvergate	230	230	1S,3	4.00		1	2-900 ACSS/AW
59	Old Town_1		230	230	1S	0.00		1	2-1109 ACAR
60		Mission_1	230	230	1S		4	2	1-1109 ACAR
61	Old Town_2		230	230	1S	0.09		1	2-1109 ACAR
62			230	230	1S		4	2	1-1109 ACAR
63	Old Town_3		230	230	4		7	2	1-3500 KCMIL CU
64		Silvergate_1	230	230	4		1	2	1-2500 KCMIL CU
65	Old Town_4		230	230	4		7	2	1-3500 KCMIL CU
66		Silvergate	230	230	4		1	2	1-2500 KCMIL CU
67	Talega		230	230	1S,3	34.24		1	1-1033.5 ACSR/AW
68			230	230	3		8	2	1-1033.5 ACSR/AW
69		Escondido	230	230	1S,3		9	2	1-1033.5 ACSR/AW
70	Otay Mesa		230	230	1S	0.11		1	2-900 ACSS/AW
71		Tijuana	230	230	3	2.00		1	2-1033.5 ACSR/AW
72	Otay Mesa	Miguel	230	230	1S,3		9	2	2-900 ACSS/AW
73	Miguel		230	230	1S,3		24	2	2-1033.5 ACSR/AW
74	_3		230	230	3		1	2	2-605 ACSS/AW
75		Sycamore	230	230	3		4	2	2-1109 ACAR
76	Otay Mesa	Miguel	230	230	1S,3		9	2	2-900ACSS/AW
77	Miguel		230	230	1S		10	2	2-900ACSS/AW
78		Bay Blvd	230	230	4	0.17		1	2-5000 KCMIL CU
79	Imperial Valley	NOSDGE23043_1	230	230	1S	0.00		1	2-1033.5 ACSS/AW
80	IV Bay 12N	NOSDGE23045-6_1	230	230	1S	0.00		2	2-1113 ACSR
81	IV Bay 13N	NOSDGE23045-6_1	230	230	1S	0.00		2	2-1113 ACSR
82	IV Bay 13S	NOSDGE23047-8_1	230	230	1S	0.00		2	2-954 AL
83	IV Bay 14S	NOSDGE23047-8_1	230	230	1S	0.00		2	2-954 AL
84	Imperial Valley	La Rosita	230	230	1S,2S,3		6	2	2-900 ACSS/AW
85	Palomar Energy		230	230	1S		1	2	2-900 ACSS/AW
86			230	230	1S,3		12	2	2-1109 ACAR
87	_1		230	230	3	6.18		1	2-1109 ACAR
88	_2		230	230	1S		5	2	2-1033.5 ACSR/AW
89		Sycamore	230	230	1S	0.36		1	2-1033.5 ACSR/AW
90	Talega		230	230	3	0.00		1	2-1033.5 ACSR/AW
91			230	230	1S,3		6	2	1-1033.5 ACSR/AW
92		San Onofre_1	230	230	2S		1	2	2-1033.5 ACSR/AW
93	Encina_1		230	230	1S,3		10	2	2-1109 ACAR
94		Penasquitos	230	230	1S,3		8	2	2-1033.5 ACSR/AW
95	Sycamore Canyon		230	230	1S,3		22	2	2-900 ACSS/AW
96		Suncrest	230	230	4		6	2	2-4000 KCMIL CU
97	Sycamore Canyon		230	230	1S,3		22	2	2-900 ACSS/AW
98		Suncrest_1	230	230	4		6	2	2-4000 KCMIL CU
99	SCR	SCR SVC SUB	230	230
100	Imperial Valley	NOSDGE23061_1	230	230	1S	0.00		1	2-900 ACSS/AW
101	Imperial Valley		230	230	1S		3	2	2-900 ACSS/AW
102			230	230	2S		0	2	2-900 ACSS/AW
103			230	230	3		2	2	2-900 ACSS/AW
104		Drew Switchyard	230	230	3S		0	1	2-900 ACSS/AW
105	Drew Switchyard	NOSDGE23067_1	230	230	1S	0.00		1	2-900 ACSS/AW
106	Drew Switchyard	POCO	230	230	1S	0.00		1	1-900 ACSS/AW
107	DREW Switchyard	DW GEN 7	230	230	1S	0.00		1	1-1250 KCMIL AL
108	Pio Pico Generator	Otay Mesa Sy	230	230	1S	0.04		1	1-1272 ACSS
109	Penasquitos		230	230	1S		3	2	2-900 ACSS/AW
110	_1		230	230	4	11.00		1	2-4000 KCMIL CU
111			230	230	4	1.00		1	2-4000 KCMIL CU ENAMEL
112		Sycamore Canyon	230	230	4	0.00		1	2-5000 KCMIL CU ENAMEL
113	Encina	Encina Gen 1	230	230	4	0.03		1	1-3500 CU
114	OM	OM GEN 4	230	230	1S		0	1	1-1033.5 ACSR/AW
115	San Luis Rey		230	230	1S		0	2	2-1033.5 ACSR/AW
116		GIS Terminal	230	230	4		0	2	1-5000 KCMIL CU
117	San Luis Rey_1		230	230	1S		0	2	2-1033.5 ACSR/AW
118		GIS Terminal_2	230	230	4		0	2	1-5000 KCMIL CU
119	Imperial Valley	Phase Shifting Transformer	230	230	1S		0	2	2-900 ACSS/AW
120	Z172244	Z172242	230	230	1S		0	2	2-1033.5 ACSR/AW
121	Z189533	Z189535	230	230	3	0.27		1	1-1033.5 ACSR/AW
122	East County	Eco Gen 1	230	230	3		0	2	2-1113 ACSS/AW
123	Drew Switchyard		230	230	1S		2	2	2-900 ACSS/AW
124		Z46503	230	230	3		1	2	2-900 ACSS/AW
125	Encina Switchyard		138	230	1S		0	2	2-1033.5 ACSR/AW
126		Cannon	138	230	1S		0	2	2-1109 ACAR
127	Encina Switchyard		138	230	1S,3		1	2	2-1109 ACAR
128			138	230	2W,1S,2S,3S,3	17.00		1	2-636 ACSR/AW
129	Z105030	Batiquitos	138	230	4	1.00		1	1-1750 MCM AL
130			138	230	4	0.72		1	2-1750 MCM AL
131		Penasquitos	138	230	3		3	2	2-1033.5 ACSR/AW
132	Palomar		138	138	1S	0.03		1	2-1033.5 ACSR/AW
133		Batiquitos	138	230	1S		3	2	2-1109 ACAR
134	Encina Switchyard_1		138	230	1S,3		1	2	2-1109 ACAR
135		Palomar	138	230	1S,2S,3		2	2	2-1033.5 ACSR/AW
136	Telegraph Canyon	Proctor Valley	138	138	1W,1S,3		3	2	2-636 ACSS/AW
137	Friars		138	138	4	0.17		1	2-2500 CU
138	_1		138	138	1S,3		4	2	1-636 ACSR/AW
139			138	138	1S,3		2	2	1-400 MCM CU
140	_2		138	138	1S,3	5.43		1	1-636 ACSR/AW
141		Penasquitos	138	138	1S,3		1	2	1-636 ACSR/AW
142	Doublet Tap		138	138	1W,1S		1	3	1-336 ACSR/AW
143		Doublet	138	138	1W,1S		1	2	1-336 ACSR/AW
144	Shadowridge	Z119772	138	138	1S		4	2	1-1033.5 ACSR/AW
145	Z119772		138	138	1W,1S,3	0.00		1	1-250 MCM CU
146		NC Metering	138	138	1W	0.39		1	1-336 ACSR/AW
147	Z119772		138	230	3		1	2	2-1033.5 ACSR/AW
148		Chicarita	138	138	2W,2S	11.00		1	1-636 ACSR/AW
149	Telegraph Canyon		138	138	1S	0.03		1	2-1033.5 ACSR/AW
150			138	138	3		6	2	2-636 ACSR/AW
151			138	138	4	4.04		1	1-2500 KCMIL CU
152	Z223732		138	138	3			1	1-1033.5 ACSR/AW
153		Z189532	138	138	3	4.00		1	2-400 MCM CU
154			138	138	3	0.00		1	2-636 ACSS/AW
155		Grant Hill	138	138	1W,1S	1.00		1	2-636 ACSR/AW
156	San Juan Capistrano		138	138	1W	0.10		1	1-1033.5 ACSR/AW
157			138	138	1S,3		2	2	1-1033.5 ACSR/AW
158			138	138	1S	0.11		1	1-3000 KCMIL CU
159			138	138	1S,3		5	2	1-636 ACSR/AW
160		Pico	138	138	4		0	2	1-1750 MCM CU
161	Santee		138	138	1W,1S	2.00		1	1-1033.5 ACSR/AW
162			138	138	1S		5	2	1-605 ACSS/AW
163			138	138	2S	0.00		1	2-336 ACSR/AW
164		Los Coches	138	138	2S	0.00		1	2-636 ACSR/AW
165	Sycamore		138	138	4	0.20		1	1-3000 KCMIL CU
166		Chicarita	138	138	1W,2W,1S,2S	6.00		1	1-636 ACSR/AW
167	Sycamore		138	138	1S		7	2	1-900 ACSS/AW
168		Santee	138	138	1W,1S	1.55		1	1-900 ACSS/AW
169	Mission		138	138	1W	0.00		1	2-336.4 ACSR
170			138	138	1S,3		3	2	2-336.4 ACSR
171	Z677977	Z874970	138	138	3	5.00		2	4-336.4 MCM
172	Z874970	Carlton Hills	138	138	1S,3		1	2	1-900 ACSS/AW
173	Telegraph Canyon		138	138	1S	0.04		1	2-1033.5 ACSR/AW
174			138	138	1S,3		3	2	2-636 ACSR/AW
175		Miguel 60 Tap	138	138	1S,3		1	2	2-636 ACSR/AW
176	Miguel 60 Tap	Miguel	138	138	1S		1	2	2-900 ACSS/AW
177	Miguel 60 Tap	Z119793	138	138	1S	0.02		1	2-636 ACSS/AW
178	Z119793	Z200591	138	138	1S,2S	0.50		1	2-636 ACSR/AW
179			138	138	1S,3		13	2	1-636 ACSS/AW
180		Los Coches	138	138	1S,3		1	2	1-636 ACSR/AW
181	Batiquitos		138	138	1S		3	2	2-1033.5 ACSR/AW
182		Shadowridge	138	138	1S		4	2	2-1033.5 ACSR/AW
183	Miguel		138	138	1S	1.00		1	2-636 ACSS/AW
184		Proctor Valley	138	138	1S,3		1	2	2-636 ACSR/AW
185	Friars		138	138	4	0.09		1	1-1750 KCMIL AL
186		Mission	138	138	1S,3		1	2	1-900 ACSS/AW
187	Sycamore_1		138	138	1S		4	2	1-900 ACSS/AW
188			138	138	1S		2	2	1-900 ACSS/AW
189		Carlton Hills	138	138	1S,3		1	2	1-900 ACSS/AW
190	Trabuco		138	138	1S	1.00		1	1-1033.5 ACSR/AW
191			138	138	1S	0.00		1	2-1033.5 ACSR/AW
192			138	138	4	3.00		1	1-1750 KCMIL AL
193		Margarita	138	138	4	0.00		1	1-1750 KCMIL CU
194	Talega	Rancho Mission Viejo	138	138	1W,1S	6.42		1	1-1033.5 ACSR/AW
195	Trabuco		138	138	1W,1S	3.66		1	1-1033.5 ACSR/AW
196			138	138	1W,3		0	2	1-1033.5 ACSR/AW
197	_1		138	138	1S,3		6	2	1-1033.5 ACSR/AW
198		Pico_1	138	138	4		0	2	1-1750 MCM CU
199	Capistrano		138	138	1W	4.00		1	1-1033.5 ACSR/AW
200		Trabuco	138	138	1W		0	2	1-1033.5 ACSR/AW
201	San Mateo_1	Talega	138	138	1W,1S	1.00		1	1-1033.5 ACSR/AW
202	Talega Tap_1		138	138	1W,3		3	2	1-336.4 ACSR/AW
203	_2		138	138	1W,2W,1S,2S,3	8.00		1	1-336.4 ACSR/AW
204	_1		138	138	4		2	2	1-1750 KCMIL AL
205		Laguna Niguel_1	138	138	4	0.00		1	1-1750 KCMIL AL
206	Pico		138	138	1S,3		1	2	1-900 ACSS/AW
207		Talega	138	138	1W	0.41		1	1-1033.5 ACSR/AW
208	Capistrano		138	138	1W	0.00		1	1-636 ACSR/AW
209			138	138	1W		0	2	1-336.4 ACSR/AW
210			138	138	1W,1S	1.00		1	1-336.4 ACSR/AW
211		Laguna Niguel	138	138	4		2	2	1-1750 KCMIL AL
212	Rancho Mission Viejo	Margarita	138	138	1W,1S	3.00		1	1-1033.5 ACSR/AW
213	Mission		138	138	1W,1S	2.56		1	2-636 ACSR/AW
214		Grant Hill	138	138	4	3.00		1	1-2500 MCM CU
215	Cannon	Encina Hub	138	138	1S,3		1	2	2-1109 ACAR
216	Encina Hub	Shadowridge	138	138	1S,2S,2W	7.00		1	1-900 ACSS/AW
217	East County		138	138	1S,2S	7.00		1	2-900 ACSS/AW
218			138	138	4	6.00		1	2-2500 KCMIL CU
219			138	138	4	1.12		1	2-3000 KCMIL CU
220		Boulevard East	138	138	4	0.00		1	2-5000 KCMIL CU
221	Pico		138	138	3		1	2	1-1033.5 ACSR/AW
222		Talega	138	138	1W,1S	0.47		1	1-1033.5 ACSR/AW
223	Talega		138	138	3		3	2	1-336.4 ACSR/AW
224		San Mateo	138	138	1S		1	2	1-1033.5 ACSR/AW
225	Encina	Z124528	138	230	1S		0	2	2-1033.5 ACSR
226	Z124528	Cannon	138	230	1S		0	2	2-1109 ACAR
227	Boulavard	Boulevard East	238	138	4		1	1	2-2500 KCMIL CU
228	East County	Eco Gen 2	138	138	1S	0.00		1	1-636 ACSR/AW
229	Encina	Encina Gen 1	138	138	3S	0.00		1	1-636 KCMIL ACSR
230	13822	De-Energized	138	138	2W	0.00		1	1-1109 ACAR
231	13832	De-Energized	138	138	3,1S,1W	3.00		1	1-336.4 ACSR
232	13832	De-Energized	138	138	3,1S,1W	3.00		1	1-250 MCM CU
233	13811	De-Energized	138	138	1S	1.07		1	1-900 ACSS/AW
234	13811	De-Energized	138	138	3	6.00		1	1-250 MCM CU
235	Cannon_1	Encina Hub	138	138	1S,3		1	2	2-1109 ACAR
236	Encina Hub	Calavera Tap	138	138	2W	0.00		1	1-1033.5 ACSR/AW
237	Encina Hub	Calavera Tap	138	138	2W	2.94		1	1-636 ACSS/AW
238	Calavera Tap	San Luis Rey	138	138	2W	3.89		1	1-1033.5 ACSR/AW
239	Bay Blvd		138	138	3		3	2	2-636 ACSR/AW
240		Telegraph Canyon	138	138	3		3	2	2-400 MCM CU
241	69 kV CIRCUITS				1W	707.00	25	125
242	69 kV CIRCUITS				2W	7.00	1
243	69 kV CIRCUITS				1S	43.00	2
244	69 kV CIRCUITS				3	20.00	51
245	69 kV CIRCUITS				4	62.00	1
246	Cost of Line									(d) 205,126,609	(e) 3,680,008,465	(f) 3,885,135,074
247	Expenses, Except ISO Charge												(g) 17,861,047	(i) 26,129,028	(j) 3,946,818	(k) 47,936,893
248	ISO Charges												(h) 3,708,419			(l) 3,708,419
36	TOTAL					1,445	680	514		205,126,609	3,680,008,465	3,885,135,074	21,569,466	26,129,028	3,946,818	51,645,312

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: LengthForStandAloneTransmissionLines

San Diego Gas & Electric owns 85.64% and Imperial Irrigation District owns 14.36%.

(b) Concept: LengthForStandAloneTransmissionLines

San Diego Gas & Electric owns 85.64% and Imperial Irrigation District owns 14.36%.

(c) Concept: LengthForStandAloneTransmissionLines

Line has two sections: Palo Verde to North Gila, and North Gila to Colorado River. SDG&E owns 76.22% and 85.64%, respectively, while Arizona Public Service owns 23.78% and 14.36%, respectively.

(d) Concept: CostOfLandAndLandRightsTransmissionLines

Costs available in total only.

(e) Concept: ConstructionAndOtherCostsTransmissionLines

Costs available in total only.

(f) Concept: OverallCostOfTransmissionLine

Costs available in total only.

(g) Concept: OperatingExpensesOfTransmissionLine

Costs available in total only.

(h) Concept: OperatingExpensesOfTransmissionLine

Costs available in total only.

(i) Concept: MaintenanceExpensesOfTransmissionLine

Costs available in total only.

(j) Concept: RentExpensesOfTransmissionLine

Costs available in total only.

(k) Concept: OverallExpensesOfTransmissionLine

Costs available in total only.

(l) Concept: OverallExpensesOfTransmissionLine

Costs available in total only.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSMISSION LINES ADDED DURING YEAR
Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
1	OVERHEAD
2	Z125642	Z31482	(a) 0.14	OH	6	2	2	1-1033.5	ACSR/AW	9'	138		761,929	507,913		1,269,842
3	SAN JUAN CAPISTRANO	Z125642	(b) 0.12	OH	6	2	2	1-1033.5	ACSR/AW	9'	138				575,708	575,708
4	LOVELAND_1	Z293866	0.34	OH	9	2	2	1-636	ACSS/AW	9'	69
5	LOVELAND_2	Z293866	(c) 0.34	OH	9	2	2	1-636	ACSS/AW	9'	69		541,083	96,102		637,185
6	LAS PULGAS_1	JAPANESE MESA	(d) 6.65	OH	9	1	1	1-636	ACSR/AW	9'	69	1,732,888	10,423,043	3,938,625		16,094,556
7	LAS PULGAS_2	JAPANESE MESA	(e) 6.66	OH	9	1	1	1-4/0	CU B.S.	6'	69				1,982,819	1,982,819
8	UNDERGROUND
9	SAN JUAN CAPISTRANO	Z125642	(f) 0.11	UG		1	1	401769	KCMIL CU	9"	138			913,080		913,080
10	Z293865_1	Z293866	0.08	UG		2	2	1-1750	KCMIL CU	9"	69
11	Z293865_2	Z293866	(g) 0.08	UG		2	2	1-1750	KCMIL CU	9"	69			2,250,327		2,250,327
44	TOTAL		1.20		48	15	15					1,732,888	11,726,055	7,706,047	2,558,527	23,723,517

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: LengthOfTransmissionLineAdded

To report addition of 0.14 miles for TL13816 from Structure Z125642 to Structure Z31482 for 2021.

(b) Concept: LengthOfTransmissionLineAdded

To report removal of 0.12 miles for TL13816 from San Juan Capistrano Substation to Structure Z125642 for 2021.

(c) Concept: LengthOfTransmissionLineAdded

To report addition of 0.34 miles for TL6914 and TL6957 from Loveland Substation to Structure Z293866 for 2021.

(d) Concept: LengthOfTransmissionLineAdded

To report re-build of 6.65 miles for TL692 from Las Pulgas Substation to Japanese Mesa Substation for 2021.

(e) Concept: LengthOfTransmissionLineAdded

To report removal of 6.66 miles for TL692 from Las Pulgas Substation to Japanese Mesa Substation for 2021.

(f) Concept: LengthOfTransmissionLineAdded

To report addition of 0.11 miles for TL13816 from San Juan Capistrano Substation to Structure Z125642 for 2021.

(g) Concept: LengthOfTransmissionLineAdded

To report addition of 0.08 miles for TL6914 and TL6957 from Structure Z293865 to Structure Z293866 for 2021.

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	ALPINE, Alpine	Distribution	Unattended	69	12	0	56	2
2	AMHERST, San Diego	Distribution	Unattended	12	4	0	6	1
3	ARTESIAN, San Diego	Distribution	Unattended	69	12	0	56	2
4	ASH, Escondido	Distribution	Unattended	69	12	0	84	3	1
5	AVOCADO, Fallbrook	Distribution	Unattended	69	12	0	41	2
6	B , San Diego	Distribution	Unattended	69	12	0	112	4
7	BARRETT, Barrett	Distribution	Unattended	69	12	0	13	1
8	BASILONE, San Clemente	Distribution	Unattended	69	12	0	28	1
9	BATIQUITOS, Encinitas	Distribution	Unattended	138	12	0	56	2	1
10	BERNARDO, Rancho Bernardo	Distribution	Unattended	69	12	0	140	5
11	BORDER-, San Diego	Distribution	Unattended	69	12	0	56	2
12	BORREGO-, Borrego Springs	Distribution	Unattended	69	12	0	26	2
13	BOSTONIA, El Cajon	Distribution	Unattended	12	4	0	10	1
14	BOULEVARD EAST, Boulevard	Distribution	Unattended	138	12	0	28	1
15	CABRILLO, San Diego	Distribution	Unattended	69	12	0	56	2
16	CALAVO GARDENS, El Cajon	Distribution	Unattended	12	4	0	7	2
17	CAMERON, Campo	Distribution	Unattended	69	12	0	6	1
18	CANNON, Carlsbad	Distribution	Unattended	138	12	0	112	4
19	CAPISTRANO, San Juan Capistrano	Distribution	Unattended	138	12	0	56	2
20	CARLTON HILLS, Santee	Distribution	Unattended	138	12	0	56	2
21	CENTRAL, San Diego	Distribution	Unattended	12	4	0	6	1
22	CHICARITA, San Diego	Distribution	Unattended	138	12	0	84	3
23	CHOLLAS , Lemon Grove	Distribution	Unattended	69	12	0	56	2	1
24	CLAIREMONT, San Diego	Distribution	Unattended	69	12	0	56	2
25	CORONADO, Coronado	Distribution	Unattended	69	12	0	56	2
26	CREELMAN, Ramona	Distribution	Unattended	69	12	0	84	3
27	CRESTWOODCampo	Distribution	Unattended	69	12	0	13	1
28	CRISTIANITOS Mission Viejo	Distribution	Unattended	69	12	0	8	1
29	DEL MAR, Del Mar	Distribution	Unattended	69	12	0	84	3
30	DESCANSO, Descanso	Distribution	Unattended	69	12	0	7	1
31	DIVISION, San Diego	Distribution	Unattended	69	12	0	53	2
32	DUNHILL-San Diego	Distribution	Unattended	69	4	0	8	1
33	EAST OCEANSIDE, Oceanside	Distribution	Unattended	12	4	0	6	1
34	EASTGATE, San Diego	Distribution	Unattended	69	12	0	56	2
35	EL CAJON, El Cajon	Distribution	Unattended	69	12	0	112	4
36	ELLIOTT, San Diego	Distribution	Unattended	69	12	0	84	3
37	ENCINITAS_1, Encinitas	Distribution	Unattended	69	12	0	56	2
38	ENCINITAS_2, Encinitas	Distribution	Unattended	12	4	0	6	1
39	ESCO_1, Escondido	Distribution	Unattended	69	12	0	56	2
40	ESCO_2, Escondido	Distribution	Unattended	12	4	0	4	1
41	ESCONDIDO, Escondido	Distribution	Unattended	69	12	0	112	4
42	F , San Diego	Distribution	Unattended	69	12	0	84	3
43	FELICITA,Escondido	Distribution	Unattended	69	12	0	84	3
44	FRIARS, San Diego	Distribution	Unattended	138	12	0	56	2
45	GARFIELD, El Cajon	Distribution	Unattended	69	12	0	28	1
46	GENESEE,San diego	Distribution	Unattended	69	12	0	112	4
47	GLENCLIFF-GC	Distribution	Unattended	69	12	0	7	1
48	GRANITE, El Cajon	Distribution	Unattended	69	12	0	112	4
49	GRANT HILLSan Diego	Distribution	Unattended	138	12	0	56	2
50	HILLTOP, San Diego	Distribution	Unattended	12	4	0	3	1
51	IMPERIAL BEACH_1, Imperial Beach	Distribution	Unattended	69	12	0	56	2
52	IMPERIAL BEACH_2, Imperial Beach	Distribution	Unattended	12	4	0	6	1
53	JAMACHA, Jamacha	Distribution	Unattended	69	12	0	84	3
54	JAPANESE MESA, San Clemente	Distribution	Unattended	69	12	0	14	2
55	KEARNY WEST, San Diego	Distribution	Unattended	69	12	0	112	4	1
56	KETTNER,San Diego	Distribution	Unattended	69	12	0	56	2
57	KYOCERA, San Diego	Distribution	Unattended	69	12	0	9	1
58	LA JOLLA, La Jolla	Distribution	Unattended	69	12	0	56	2
59	LAGUNA NIGUEL, Laguna Niguel	Distribution	Unattended	138	12	0	112	4
60	LAS PULGAS-Oceanside	Distribution	Unattended	69	12	0	28	1
61	LILAC, Valley Center	Distribution	Unattended	69	12	0	56	2
62	LINCOLN ACRES, National City	Distribution	Unattended	12	4	0	6	1
63	LOS COCHES, Lakeside	Distribution	Unattended	69	12	0	84	3
64	LOVELAND, Alpine	Distribution	Unattended	69	12	0	28	1
65	MARGARITA, Mission Viejo	Distribution	Unattended	138	12	0	112	4
66	MELROSE, Vista	Distribution	Unattended	69	12	0	112	4
67	MESA HEIGHTS,SanDiego	Distribution	Unattended	69	12	0	84	3
68	MESA RIM, San Diego	Distribution	Unattended	69	12	0	112	4
69	MIRAMAR, San Diego	Distribution	Unattended	69	12	0	84	3
70	MIRA SORRENTO,San Diego	Distribution	Unattended	69	12	0	56	2
71	MISSION, San Diego	Distribution	Unattended	69	12	0	112	4
72	MONSERATE, Fallbrook	Distribution	Unattended	69	12	0	56	2
73	MONTGOMERY, Chula Vista	Distribution	Unattended	69	12	0	56	2
74	MORRO HILL, Oceanside	Distribution	Unattended	69	12	0	13	1
75	MURRAY, La Mesa	Distribution	Unattended	69	12	0	112	4	1
76	NATIONAL CITY, National City	Distribution	Unattended	69	4	12	14	2
77	NAVAL STATION Switchyard, San Diego-NSM	Distribution	Unattended	69		0	0	0
78	NORTH CITY WEST, San Diego	Distribution	Unattended	69	12	0	56	2
79	NORTH VISTA-,Vista	Distribution	Unattended	12	4	0	3	1
80	OCEAN RANCH, Oceanside	Distribution	Unattended	69	12	0	56	2
81	OCEANSIDE, Oceanside	Distribution	Unattended	69	12	0	56	2
82	OLD TOWN, San Diego	Distribution	Unattended	69	12	0	84	3	2
83	OLIVENHAIN-, Escondido	Distribution	Unattended	69	12	0	28	1
84	OTAY LAKES, Chula Vista	Distribution	Unattended	69	12	0	5	1
85	OTAY. Chula Vista	Distribution	Unattended	69	12	0	56	2	1
86	PACIFIC BEACH, San Diego	Distribution	Unattended	69	12	0	56	2
87	PALA, San Diego County	Distribution	Unattended	69	12	0	28	1
88	PALOMAR AIRPORT, Carlsbad	Distribution	Unattended	138	12	0	84	3
89	PARADISE, San Diego	Distribution	Unattended	69	12	0	56	2
90	PENDLETON, Oceanside	Distribution	Unattended	69	12	0	56	2
91	PICO, San Clemente	Distribution	Unattended	138	12	0	56	2
92	POINT LOMA SEWAGE, San Diego	Distribution	Unattended	12	4	0	13	1
93	POINT LOMA, San Diego	Distribution	Unattended	69	12	0	84	3
94	POMERADO, San Diego	Distribution	Unattended	69	12	0	84	3
95	POWAY, Poway	Distribution	Unattended	69	12	0	56	2
96	PROCTOR VALLEY, Bonita	Distribution	Unattended	138	12	0	56	2	1
97	RAMONA, Ramona	Distribution	Unattended	12	4	0	6	1
98	RANCHO CARMEL, San Diego	Distribution	Unattended	69	12	0	84	3
99	RANCHO MISSION VIEJO, Rancho Mission Viejo	Distribution	Unattended	138	12	0	56	2
100	RANCHO SANTA FE_1, RanchoSantaFe	Distribution	Unattended	69	12	0	41	2
101	RANCHO SANTA FE_2, RanchoSantaFe	Distribution	Unattended	69	4	0	6	1
102	RINCON, Rincon	Distribution	Unattended	69	12	0	25	2
103	ROLANDO, San Diego	Distribution	Unattended	12	4	0	13	2
104	ROSE CANYON, San Diego	Distribution	Unattended	69	12	0	56	2
105	SALT CREEK, Chula Vista	Distribution	Unattended	69	12	0	56	2
106	SAMPSON, San Diego	Distribution	Unattended	69	12	0	112	4
107	SAN CLEMENTE, San clemente	Distribution	Unattended	12	4	0	3	1
108	SAN LUIS REY-Oceanside	Distribution	Unattended	69	12	0	112	4
109	SAN MARCOS, San Marcos	Distribution	Unattended	69	12	0	112	4
110	SAN MATEO, San Clemente	Distribution	Unattended	138	12	0	45	2
111	SAN YSIDRO, San Ysidro	Distribution	Unattended	69	12	0	56	2
112	SANTA YSABEL, Santa Ysabel	Distribution	Unattended	69	12	0	12	1
113	SANTEE, Santee	Distribution	Unattended	138	12	0	56	2
114	SCRIPPS, San Diego	Distribution	Unattended	69	12	0	84	3
115	SEWAGE PUMP STA (3)., San Diego	Distribution	Unattended	12	4	0	46	6
116	SHADOWRIDGE, Vista	Distribution	Unattended	138	12	0	84	3
117	SHORECLIFFS-San Clemente	Distribution	Unattended	12	4	0	3	1
118	SOUTH SAN CLEMENTE, San clemente	Distribution	Unattended	12	4	0	3	1
119	SPRING VALLEY, Spring Valley	Distribution	Unattended	69	12	0	56	2
120	STREAMVIEW, San Diego	Distribution	Unattended	69	12	0	56	2
121	STUART, Oceanside	Distribution	Unattended	69	12	0	8	1
122	SUNNYSIDE, San Diego	Distribution	Unattended	69	12	0	28	1
123	SWEETWATER, National City	Distribution	Unattended	69	12	0	56	2	1
124	TELEGRAPH CANYON, Chula Vista	Distribution	Unattended	138	12	0	112	4
125	TORREY PINES, San Diego	Distribution	Unattended	69	12	0	112	4
126	TRABUCO, San Juan Capistrano	Distribution	Unattended	138	12	0	112	4
127	UCM switchyard, San Diego	Distribution	Unattended	69
128	URBAN-, San Diego	Distribution	Unattended	69	12	0	84	3
129	VALLEY CENTER, Valley Center	Distribution	Unattended	69	12	0	28	1
130	VINE	Distribution	Unattended	69	12	0	56	3
131	VISTA, Vista	Distribution	Unattended	12	4	0	10	2
132	WARNERS. Warner Springs	Distribution	Unattended	69	12	0	28	1
133	WARREN CANYON_1, Poway	Distribution	Unattended	69	12	0	8	1
134	WARREN CANYON_2, Poway	Distribution	Unattended	69	4	0	7	1
135	WITHERBY-San Diego	Distribution	Unattended	12	4	0	6	1
136	BAY BOULEVARD	Transmission	Unattended	230	69	0	448	2
137	DOUBLETT switchyard, San Diego	Transmission	Unattended	138	69
138	EAST COUNTY_1, Boulevard	Transmission	Unattended	500	230	12	1120	1
139	EAST COUNTY_2, Boulevard	Transmission	Unattended	230	138	0	392	1
140	ENCINA switchyard, Carlsbad	Transmission	Unattended	138
141	ENCINA, Carlsbad	Transmission	Unattended	230	138	0	784	2
142	ESCONDIDO, Escondido	Transmission	Unattended	230	69	0	672	3
143	GOAL LINE, Escondido	Transmission	Unattended	69
144	IMPERIAL VALLEY, El Centro	Transmission	Unattended	500	230	12	2840	9	2
145	LOS COCHES, Lakeside	Transmission	Unattended	138	69	0	448	2
146	MIGUEL_1, Bonita	Transmission	Unattended	230	69	0	448	2
147	MIGUEL_2, Bonita	Transmission	Unattended	230	138	0	784	2
148	MIGUEL_3, Bonita	Transmission	Unattended	500	230	12	2240	6	1	500/17	2	500
149	MIRAMAR GT, San Diego	Transmission	Unattended	12	69	0	50	1
150	MISSION_1, San Diego	Transmission	Unattended	138	69	0	200	1
151	MISSION_2, San Diego	Transmission	Unattended	230	69	0	224	1
152	MISSION_3, San Diego	Transmission	Unattended	230	138	0	784	2
153	NARROWS, borrego Springs	Transmission	Unattended	88	69	12	10	3
154	OCOTILLO switchyard, Ocotillo	Transmission	Unattended	500
155	OLD TOWN, San Diego	Transmission	Unattended	230	69	0	448	2
156	OTAY MESA switchyard, Chula Vista	Transmission	Unattended	230
157	PENASQUITOS_1, San Diego	Transmission	Unattended	138	69	0	520	3
158	PENASQUITOS_2, San Diego	Transmission	Unattended	230	138	0	392	1	1
159	PENASQUITOS_3, San Diego	Transmission	Unattended	230	69	0	448	2
160	SAN LUIS REY, Oceanside,	Transmission	Unattended	230	69	0	672	3		230/17	2	500
161	SILVERGATE, San Diego	Transmission	Unattended	230	69	0	448	2	1
162	SONGS	Transmission	Unattended	230	230	0	250			230/17	1	250
163	SUNCREST, Japatul	Transmission	Unattended	500	230	12	2240	6	1
164	SYCAMORE CANYON_1, San Diego	Transmission	Unattended	230	69	0	672	3	1
165	SYCAMORE CANYON_2, San Diego	Transmission	Unattended	230	138	0	392	1	1
166	TALEGA_1, San Clemente	Transmission	Unattended	138	69	0	140	1	1
167	TALEGA_2, San Clemente	Transmission	Unattended	230	138	0	1102	4		230/17	2	500
168	WABASH switchyard, San Diego	Transmission	Unattended	69		0
169	Total											1,750

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	Construction Work in Progress	Sempra Energy	107	(a) 5,962,280
3	Underground line expenses	Sempra Energy	584	71
4	Meter Expenses	Sempra Energy	586	8,712
5	Miscellaneous Distribution Expenses	Sempra Energy	588	260,633
6	Maintenance supervision and engineering	Sempra Energy	590	785
7	Maintenance of station equipment	Sempra Energy	592	612
8	Maintenance of Overhead Lines	Sempra Energy	593	5,201
9	Maintenance of Lines	Sempra Energy	594	495
10	Maintenance of meters	Sempra Energy	597	516
11	Operation supervision and engineering	Sempra Energy	850	6,003
12	Compressor station labor and expenses	Sempra Energy	853	238
13	Measuring and regulating station expenses.	Sempra Energy	857	261
14	Maintenance of mains	Sempra Energy	863	26,131
15	Maintenance of measuring and regulating station equipment	Sempra Energy	865	87
16	Operation Supervision and Engineering	Sempra Energy	870	54,443
17	Mains and services expenses	Sempra Energy	874	14,873
18	Meter and House Regulator Expenses	Sempra Energy	878	394
19	Customer installations expenses	Sempra Energy	879	25,369
20	Distribution Other Expenses	Sempra Energy	880	35,320
21	Other Utility Plant	Sempra Energy	118	227,935
22	Maintenance of mains_2	Sempra Energy	887	4,035
23	Maintenance of Services	Sempra Energy	892	45
24	Maintenance of Meters and House Regulators	Sempra Energy	893	497
25	Maintenance of other equipment.	Sempra Energy	894	58
26	Meter Reading Expenses	Sempra Energy	902	8,142
27	Customer Records and Collection Expenses	Sempra Energy	903	20,770
28	Customer Assistance Expenses	Sempra Energy	908	11,304
29	Miscellaneous Customer Service and Informational Expenses	Sempra Energy	910	478,436
30	Office Supplies and Expenses	Sempra Energy	921	793,511
31	Outside Services Employed	Sempra Energy	923	60,940,954
32	Property Insurance	Sempra Energy	924	422,094
33	Injuries and Damages	Sempra Energy	925	128,572
34	Employee Pension and Benefits	Sempra Energy	926	51,228,787
35	Regulatory Commission Expenses	Sempra Energy	928	128,835
36	Miscellaneous General Expense	Sempra Energy	930.2	1,613,323
37	Maintenance of General Plant	Sempra Energy	935	9,667
38	Purchased Power	Energia Sierra Juarez	555	17,576,300
39	Construction Work in Progress	Southern California Gas Company	107	11,761,732
40	Accounts Receivable from Associated Companies	Sempra Energy	146	888
41	Accum Prov for Deprec	Southern California Gas Company	108	9,880
42	Other Utility Plant	Southern California Gas Company	118	3,145,178
43	3rd Party Bill A/R-Clearing	Southern California Gas Company	143.8	218,163
44	Stores Expense Undistributed	Southern California Gas Company	163	673,394
45	Clearing Accounts	Southern California Gas Company	184	1,034,254
46	Miscellaneous Deferred Debits	Southern California Gas Company	186	54,461
47	RD&D EXPENDITURES	Southern California Gas Company	188	418,804
48	Accounts Payable	Southern California Gas Company	232	49,193
49	Expense of NonUtility Operations	Southern California Gas Company	417.1	32,342
50	Expenditures for Certain Civic, Political and Related Activities	Southern California Gas Company	426.4	81,639
51	Other Gas Revenues	Southern California Gas Company	495	409,050
52	Miscellaneous Transmission Expenses	Southern California Gas Company	566	3,153
53	Miscellaneous Distribution Expenses	Southern California Gas Company	588	804
54	Natural Gas TR Line Prch	Southern California Gas Company	803	6,592
55	Cpmpressor Stn Exp	Southern California Gas Company	818	64,211
56	GTO Operations Supervision & Engineering	Southern California Gas Company	850	4,797,241
57	System Control & Load Dispatch	Southern California Gas Company	851	918,759
58	Communication System Expenses	Southern California Gas Company	853	1,641,177
59	Stores Expense Undistributed	Sempra Energy	163	5,558
60	Other Expenses	Southern California Gas Company	859	518,486
61	TIMP-Main Supv & Eng	Southern California Gas Company	861	75,182
62	GTM Maintenance Mains	Southern California Gas Company	863	882,746
63	Operation Supervision and Engineering	Southern California Gas Company	870	4,194,249
64	Routine Leak Survey	Southern California Gas Company	874	70,908
65	TIMP-MEAS&REG STA-CG	Southern California Gas Company	877	6,074
66	Distribution Other Expenses	Southern California Gas Company	880	90,260
67	GDM Maintenance Mains	Southern California Gas Company	887	48,413
68	Maintenance / Meters & Hse Reg	Southern California Gas Company	893	409,931
69	Meter Reading Expenses	Southern California Gas Company	902	180,816
70	Customer Records and Collection Expenses	Southern California Gas Company	903	1,742,989
71	Customer Assistance Expenses	Southern California Gas Company	908	644,838
72	Informational and Instructional Advertising Expenses	Southern California Gas Company	909	28,609
73	Outside Services Employed	Southern California Gas Company	923	62,860,321
74	Injuries and Damages	Southern California Gas Company	925	721,806
75	Employee Pension and Benefits	Southern California Gas Company	926	136,178
76	Regulatory Commission Expenses	Southern California Gas Company	928	2,335,783
77	Miscellaneous General Expense	Southern California Gas Company	930.2	174,618
78	Prepayments	Sempra Energy	165	258,293,644
79	Rents	Southern California Gas Company	931	1,427,376
80	Maintenance of General Plant	Southern California Gas Company	935	620,281
81	Unamortized Debt Expense	Sempra Energy	181	1,200,083
82	Operation supervision and engineering_1	Sempra Energy	500	748
83	Miscellaneous Steam Power Expenses_2	Sempra Energy	506	636
84	Maintenance of miscellaneous steam plant_3	Sempra Energy	514	87
85	Operation Supervision and Engineering_4	Sempra Energy	546	312
86	Miscellaneous other power generation expenses_5	Sempra Energy	549	236
87	Maintenance of miscellaneous other power generation plant_6	Sempra Energy	554	7,525
88	System control and load dispatching_7	Sempra Energy	556	36
89	Other expenses_8	Sempra Energy	557	637
90	Transmission Operation Supv & Engineering_9	Sempra Energy	560	185,450
91	Load Dispatch_10	Sempra Energy	561	1,872
92	Station expenses_11	Sempra Energy	562	1,955
93	Miscellaneous Transmission Expenses_12	Sempra Energy	566	169,165
94	Operation supplies and expenses._13	Sempra Energy	568	301
95	Maintenance of Structures_14	Sempra Energy	569	5,256
96	Maintenance of station equipment_15	Sempra Energy	570	4,087
97	Maintenance of overhead lines_16	Sempra Energy	571	1,685
98	Distribution Operation Supv & Engineering_17	Sempra Energy	580	41,621
99	Load dispatching_18	Sempra Energy	581	1,680
100	Other regulatory assets	Sempra Energy	182	624,985
101	Clearing Accounts	Sempra Energy	184	2,183,385
102	Deferred Debits	Sempra Energy	186	624,950
103	Accumulated provision for property insurance.	Sempra Energy	228.2	11
104	Accumulated miscellaneous operating provisions	Sempra Energy	228.4	112,630
105	Accounts Payable	Sempra Energy	232	247,743
106	Other Deferred Credits	Sempra Energy	253	3,677,982
107	Other regulatory liabilities	Sempra Energy	254	624,985
108	Expenses of Nonutility Operations	Sempra Energy	417.1	2,164,775
109	Expenditures for Certain Civic, Political and Related Activities	Sempra Energy	426.4	1,619
110	Other Deductions	Sempra Energy	426.5	35,011
111	Other Electric Revenues	Sempra Energy	456	1,224
19
20	Non-power Goods or Services Provided for Affiliated
21	Accounting & Finance	Sempra Energy	146	1,354,048
22	External Affairs	Southern California Gas Company	146	2,554,875
23	Human Resources	Southern California Gas Company	146	234,583
24	Information Technology	Southern California Gas Company	146	80,203,088
25	Real Estate & Facilities	Southern California Gas Company	146	1,651,963
26	Supply Management	Southern California Gas Company	146	897
27	Depreciation Expense	Sempra Energy	146	1,191,286
28	Environmental Services	Sempra Energy	146	37,948
29	External Affairs	Sempra Energy	146	268,836
30	Human Resources	Sempra Energy	146	8,952,092
31	Information Technology	Sempra Energy	146	3,307,058
32	Real Estate & Facilities	Sempra Energy	146	4,599,090
33	Supply Management	Sempra Energy	146	1,592,981
34	Depreciation Expense	Sempra International Mexico	146	4
35	Engineering / Const. Services	Sempra International Mexico	146	70,032
36	Human Resources	Sempra International Mexico	146	160,470
37	Information Technology	Sempra International Mexico	146	888,301
38	Depreciation Expense	Sempra LNG	146	15,895
39	Human Resources	Sempra LNG	146	235,019
40	Information Technology	Sempra LNG	146	632,934
41	Real Estate & Facilities	Sempra LNG	146	626
42	Supply Management	Sempra LNG	146	8,175
43	Accounting & Finance	Southern California Gas Company	146	31,012,571
44	Customer Services	Southern California Gas Company	146	172,826
45	DepreciationExpense	Southern California Gas Company	146	8,485,018
46	Engineering and Construction Services	Southern California Gas Company	146	207,075
47	Environmental Services	Southern California Gas Company	146	38,346
42

Name of Respondent:

San Diego Gas & Electric Company

This report is:

(1)

☑ An Original

(2)

☐ A Resubmission

Date of Report:

04/15/2022

Year/Period of Report

End of:

2021

/

Q4

FOOTNOTE DATA

(a) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

All non-power goods and services provided by affiliated companies are billed to San Diego Gas and Electric at fully loaded cost.

(Rows 2-19, 43-60, 83-100, 123-138)

Fully loaded costs include all direct expenses, indirect overheads and shared service billing. Shared service non‑power goods and service support cost are based on allocation process methodologies for Sempra Energy Corporate Center cost centers. The following information regarding multi‑factor and causal‑beneficial relationship information was provided by the Sempra Energy Corporate Center Budget and Reporting Manager and is a summary of the varying methodologies used:

• Multi‑factor basic, also known as "Four‑Factor", this method is used by a department for which there is no causal relationship. The Multi‑factor basic weights four factors equally for each business unit: Revenues, Operating Expenses, Gross Plant and Investment, and Employees

• Multi‑factor basic without ONCOR, also known as "Four‑Factor", this method is used by a department for which there is no causal relationship. The Multi‑factor basic weights four factors equally for each business unit: Revenues, Operating Expenses, Gross Plant and Investment, and Employees (EXCLUDES ONCOR)

• Multi‑factor Utility, this method uses the same four factors that appear in Multi‑factor (basic), but calculates ratios for California utility business units only

• Multi‑factor split, this method divides costs 50% to Utilities, 50% to Global. The Multi‑factor (basic) percentages are the basis for the allocation between Southern California Gas Company and San Diego Gas and Electric, and between Global Business Units

• Multi‑factor split without ONCOR, this method divides costs 50% to Utilities, 50% to Global. The Multi‑factor (basic) percentages are the basis for the allocation between Southern California Gas Company and San Diego Gas and Electric, and between Global Business Units (EXCLUDES ONCOR)

• 5 executive cost centers allocated using the weighted average of the annual labor budget for departments that report to the respective executive

• Causal - Executive Security, this method accounts for the transportation services available to Corporate officers and considers their allocation methods in general. The CEO (retained) has one dedicated driver, while the other 3 drivers are available to other executives and assumes an even allocation of Utility, Global and additional retained. The result is 25% Utility, 25% Global and 50% Retained for 4 drivers

• Causal – Fire Insurance, this method allocates all costs for Fire Insurance based on miles of electrical lines per business unit

• Causal – Full Time Employee Equivalents, total Full Time Employee equivalents (FTE’s) are used as the basis for allocation of most Human Resource departmental services provided on behalf of all the business units. The Sempra Energy Corporate Center FTE’s are re‑allocated by Multi‑factor (basic) to result in a blended rate

• Causal – Executive Full Time Employee Equivalents, this method allocated the support and administration cost for executive related services using a weighted average of participating officers. Executives are heavily weighted (75%) compared to Directors and Vice Presidents (25%). The Sempra Energy Corporate Center shared service Executives are then Multi‑factored (basic) resulting in a blended percentage

• Causal – My Info Services Contract, My Info services cost is allocated by the number of people in the My Info system. The portion of services attributable to Sempra Energy Corporate Center amount is then re‑allocated by Multi‑factor (basic) to result in a blended percentage

• Causal – Headquarter Security, this method allocates the costs of Sempra Energy Corporate Center security, excluding the Headquarter guard service contract, by the Causal - Full Time Employee Equivalent method, and allocates the Headquarter guard service contract by the ratio of employees occupying the Sempra Energy Corporate Center Headquarter building

• Causal – Tax Services, this allocation is a weighted average of the workload of each employee within the Tax department based on an annual time study. The Sempra Energy Corporate Center workload hours are re‑allocated using Multi‑factor (basic) resulting in a blended percentage

• Causal – Hyperion Financial Management and Consolidation System, this allocation is a weighted average of the headcount of Hyperion Financial Management and Consolidation System users. The Sempra Energy Corporate Center amount is then re‑allocated by Multi‑factor (basic) to result in a blended percentage for each business unit

• Causal – FLP (Financial Leadership Program), this allocation is a weighted average of the employees in the Financial Leadership Program based on the business units they support. The Sempra Energy Corporate Center workload is then re‑allocated by Multi‑factor (basic) to result in a blended percentage

• Causal - Citizenship Engagement, this method uses the Multi-Factor Basic allocation as a starting point, then reduces the percentages to exclude a portion attributed to managing costs which are retained

• Causal – Global Risk, Energy Risk Management estimates the percentage of hours worked on both market risk (energy risk and Dodd Frank) and the credit risk by business unit

• Causal – Group Executive Insurance, this method allocates the group executive insurance policy using a weighted average of covered officers, per their assigned business unit. The Sempra Energy Corporate Center FTE’s are reallocated by multi-factors

• Causal – Pension, this method allocates based on the summary value of Sempra Energy’s major pension savings funds and San Diego Gas & Electric’s Nuclear Decommissioning Trust (NDT). The Sempra Energy Corporate Center and Sempra Global value is then re-allocated by the US-based FTE’s, with Sempra Energy Corporate Center FTE’s further re-allocated based on Multi‑factor (basic)

• Causal – Treasury, for the Finance department, the Assistant Treasurer estimates percentages of effort for the business units based on significant projects requiring financing or advisory work

• Causal – Law Department, this allocation method is based on direct time charged by attorneys, paralegal and law clerks in the Archer timekeeping system during the previous Jan-Sep period. Hours for Sempra Energy Corporate Center are re-allocated by Multi-Factor Basic, resulting in a blended percentage

• Causal – Audit Plan, this method is based on the Audit hours planned for each business unit in the coming year. The portion of services attributable to Sempra Energy Corporate Center is re-allocated using Multi-Factor basic method to result in a blended percentage for each business unit

• Causal – SOX, this allocation is a weighted average of the workload of each employee within SOX Compliance based on an annual time study. Sempra Energy Corporate Center workload hours are reallocated using Multi-Factor Basic, resulting in a blended percentage

• Causal – Bank Reconciliations and Escheatment, for the Bank Reconciliation and Escheatment department, the estimated percentages of effort for the business units based on the bank reconciliation and escheatment activity for the upcoming period

• Causal – Security Services, this method accounts for the call-in transportation services available to Corporate Officers and Executives. These call-in services are primarily provided to Corporate Officers and Executives at the California Utilities and for Mexico and South America. Occasionally, these services may be provided to Officers and Executives in other business units or at Sempra Energy Corporate Center. In this instance, these costs will be directly charged to the respective business unit or retained at Sempra Energy Corporate Center

• Causal – Sempra HQ CSOC Depreciation, needs to be allocated by this method, San Diego Gas & Electric 72.7% other affiliates 25.9%

• Causal – Sacramento Office Depreciation, needs to be allocated by this method, San Diego Gas & Electric 50%, other affiliates 50%

• Causal - VP Tax, this allocation is a weighted average of the workload of each employee within the Tax department based on an annual time study. Parent workload hours are reallocated using Multi-Factor Basic, resulting in a blended percentage

• Causal – Cash Management, for the Cash Management department, the Director estimates percentages based on volumes and time involved in the business units funding activities

• Causal – Executive Benefits (Southern California Gas Company), direct restricted stock and stock options expense for Southern California Gas Company executives is allocated because some executives are shared by more than one business unit. The percentages reflect a weighted average of each executive's work distribution among business units

• Causal – Executive Benefits (San Diego Gas and Electric), direct restricted stock and stock options expense for San Diego Gas and Electric executives is allocated because some executives are shared by more than one business unit. The percentages reflect a weighted average of each executive's work distribution among business units

Shared asset allocation of depreciation expense associated with capitalized assets at each shared service entity are allocated uniquely depending on its allocation of benefit or supporting purpose, and follow as such:

• Causal – HQ Depreciation – depreciation expense & ROR related to "HQ leasehold improvements" is allocated based on the square footage directly occupied by the business units. Corporate Center's direct occupation except for the portion which is retained, is re-allocated based on the Multi-Factor base allocation

• Causal - CCURE System, this allocation is a weighted average of the number of card readers used per business unit for depreciation of the CCURE 9000 Security System. Sempra Energy Corporate Center units are reallocated using Multi-factor Basic, resulting in a blended percentage

• Causal – Headquarters Occupancy, Rent, depreciation & ROR related to new headquarters that is allocated based on the square footage directly occupied by the business units. Sempra Energy Corporate Center’s direct occupation, except for an executive portion which is retained, is reallocated based on the Multi-Factor Basic. Amenity floors in the HQ are excluded, as they benefit all occupants ratably

(Rows 163-180, 203-220, 243-244)

Fully loaded costs include all direct expenses, indirect overheads and shared service billing. Shared service non-power goods and service support cost are based on allocation process methodologies for 133 Southern California Gas Company cost centers. The following causal beneficial relationship information is a summary of the 22 varying methodologies used:

• 29 cost centers used a form of LAN ID counts to determine the shared allocation

• 28 cost centers used a ratio of miles to pipe

• 12 cost centers used a form of weighted average allocation of time by inherent knowledge of the manager/planner assessment within the cost center department

• 9 cost centers used a form of allocation of computer and/or server system and resource usage statistics

• 8 cost centers used a form of prior year project assignments as a base for the current year distribution, which is adjusted as necessary when current year projects begin or change and impact the current allocation

• 7 cost centers used a form of departmental studies based on current year budgeted activities and/or dollars

• 7 cost centers used a form of the existing current year Sempra Energy Corporate Center four factor multi factor allocation which includes weighted averages of operating revenue, operating expenses, gross plant and investment and Full Time Employee equivalent numbers

• 6 cost centers used a form of gas meter counts and service territory allocations

• 5 cost centers used a form of a ratio of horsepower in compressor engines in the service territory

• 5 cost centers used a form of Full Time Employee equivalent statistics for support

• 3 cost centers used a study based on cases worked by both regulated and non-regulated companies

• 2 cost centers used a form of an allocation of space study identifying building square footage assigned

• 2 cost centers used a study based on volumes of items mailed and payments processed and the allocation of employee time

• 2 cost centers used a form of allocation based on gas flow throughput

There was one use by a cost center of each of the remaining allocation methodologies: Communication by stakeholders

• An employee matrix

• Call volume

• Claims processed over a five-year period

• A meter ratio applied to specific budgeted activity

• A mileage ratio applied to specific budgeted activity

• The number of network sites

• The number of SAP ID’s

• A workload distribution study

(Row 21-42, 61-65)

All non‑power goods and services provided by San Diego Gas and Electric are billed at fully loaded cost.

(Row 21)

Affiliate companies charged by San Diego Gas and Electric for less than $250,000 include: Sempra International South America, Sempra International Mexico.

(Rows 21-42, 61-65)

Fully loaded costs include all direct expenses, indirect overheads and, where applicable, a labor premium required by the Enova/Pacific Enterprises Merger Decision (D.98‑03‑073) for shared service billing. The Merger Decision also requires San Diego Gas and Electric to charge employee transfer fees to an affiliated company. Shared service non‑power goods and service support cost are based on allocation process methodologies for 112 San Diego Gas and Electric cost centers. The following causal‑beneficial relationship information is a summary of the 19 varying methodologies used:

• 37 cost centers used a form of LAN ID counts to determine the shared allocation

• 19 cost centers used a form of weighted average allocation of time by inherent knowledge of the manager/planner assessment within the cost center department

• 17 cost centers used a form of an allocation of space study identifying building square footage assigned

• 9 cost centers used a form of prior year project assignments as a base for the current year distribution, which is adjusted as necessary when current year projects begin or change and impact the current allocation

• 8 cost centers use a form of workload distribution study

• 4 cost centers used the existing current year Sempra Energy Corporate Center four factor multi‑factor allocation which includes weighted averages of operating revenue, operating expenses, gross plant and investment and Full Time Employee equivalent numbers

• 3 cost centers used a form of budgeted current year project assignments

• 2 cost centers were charged 100% to Sempra Energy Corporate Center

• 2 cost centers used a form of a count of network sites

• 2 cost centers used a form of the number of contracts supported

There was one use by a cost center of each of the remaining allocation methodologies:

• An allocation of time by Vice President or Director’s assessment of planned current year project assignments within the cost center, which is adjusted as necessary when current year projects begin or change and impact the current allocation and current years budgeted activities by Affiliate

• Archibus transactional data for Facilities work requests and projects

• A unit of measure based on San Diego Gas & Electric and Southern California Gas call volume

• Based on the number of MYINFO user accounts

• A form of Full Time Employee equivalent statistics for support

• The number of full-time equivalent employees benefited by the activity

• The number of SAP ID’s

• A form of allocation of computer and/or server system and resource usage statistics

• An allocation based on the number of applications used for DevSecOps


	EOY 2021

Total Materials and Supplies (FERC 154)	132,881,569	1

As Assigned to Department for Ratemaking
Electric Department	117,275,564
Gas Department	15,606,005

Total Allowable Materials and Supplies per FERC Formula	117,275,564

Total 13-Month Average Electric M&S for 2021	121,247,303	2

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report